A cutting element includes a base and a cutting face at opposite axial ends, a side surface extending between the base and the cutting face, an edge formed between the cutting face and the side surface, an edge chamfer having a uniform size around the entire edge, and a geometric shape formed on the cutting face and defined by a concave boundary with respect to a longitudinal axis of the cutting element. The concave boundary includes multiple rounded vertices, each rounded vertex located proximate to the edge chamfer and forming a cutting tip and multiple geometric shape sides connecting the rounded vertices, wherein the geometric shape sides are concave with respect to the longitudinal axis.
A cutting element has a cutting face with a geometry including at least one protrusion spaced a radial distance apart from an edge of the cutting element, the edge extending around an entire periphery of the cutting face, and a lower portion extending within the distance between the at least one protrusion and the edge, wherein a lower portion axial height measured between the edge and a base of the at least one protrusion is less than 30 percent of a greatest axial height of the at least one protrusion measured between the base of the at least one protrusion and an axially highest point of the at least one protrusion.
A cutting element may include a body, a concave cutting face formed at a first end of the body, the cutting face including one or more cutting ridges adjacent a cutting tip that are raised above the concavity of the cutting face and having a length that is at least about 10% of a diameter of the cutting face. An edge is formed around a perimeter of the cutting face, and the edge has an edge angle defined between a tangent of the cutting face and a cylindrical side surface of the body, the edge angle being acute at the cutting tip and varying around the perimeter of the cutting face.
E21B 10/567 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
E21B 10/573 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts - characterised by support details, e.g. the substrate construction or the interface between the substrate and the cutting element
A hybrid bit includes a fixed cutting structure and a rolling cutting structure. The fixed cutting structure includes a plurality of fixed cutting elements. The rolling cutting structure is coupled to the fixed cutting structure and includes a journal bore extending through the rolling cutting structure from a leading face to a trailing face, and a radially outer surface. The rolling cutting structure also includes a plurality of cutting elements extending from the radially outer surface of the rolling cutting structure.
E21B 10/14 - Roller bits combined with non-rolling cutters other than of leading-portion type
E21B 10/567 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
E21B 10/633 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable with plural detachable cutting elements independently detachable
A bolster for a degradation pick includes a transverse cross section that is non-circular. Non-circular cross sections include square, triangular, hexagonal and other shapes. The bolster is made from a wear and/or erosion resistant material. The wear and/or erosion resistant material helps to protect the shank of the degradation pick. The bolster has a matching shape to the shape of the shank of the degradation pick.
Systems and methods discussed herein relate to applying models to downhole tool records to identify, sort, and display a subset of available downhole tool records with index information as defined by the models that have a desired relationship with a received input. The received input may be indicative of a particular device, device family, or set of features for a downhole tool. The methods may include identifying, from a set of design information stored in computer-storage media, one or more downhole tool records that correspond to the received input, applying one or more index models to the identified one or more downhole tool records, applying one or more local models to the identified one or more downhole tool records, and displaying at least some of the one or more downhole tool records, with index information as defined by the one or more index and local models.
Luminescent diamond is made by subjecting a volume of diamond grains to high-pressure/ high-temperature conditions with or without a catalyst to cause the grains to undergo plastic deformation to produce nitrogen vacancy defects in the diamond grains, increasing the luminescent activity/intensity of the resulting diamond material. The consolidated diamond material may be further treated to further increase luminescent activity/intensity, which treatment may comprise reducing the consolidated diamond material to diamond particles, heat treatment in vacuum, and air heat treatment, which reducing process further increases luminescent activity/intensity. The resulting luminescent diamond particles display a level of luminescence intensity greater than that of conventional luminescent nanodiamond, and may be functionalized for use in biological applications.
C04B 35/52 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on carbon, e.g. graphite
A cutting element may include a substrate having a non-planar upper surface with a peripheral edge, and an ultrahard layer. The upper surface may include at least one depression formed at least proximate the peripheral edge; and a compressive stress hoop extending around the upper surface adjacent the peripheral edge, extending into the at least one depression, and configured to reduce tensile stress in the ultrahard layer. The ultrahard layer may be on the substrate and may have a non-planar top surface and an interface formed between the ultrahard layer and the substrate.
A tool for removing material includes a body, an ultrahard insert, and a matrix. The body has a forward portion, an opposing rear portion, and a longitudinal axis therebetween. The ultrahard insert includes an ultrahard material, and the ultrahard insert is mounted to and contacts the body proximate the forward portion. The matrix contacts the body and the ultrahard insert. The matrix is mechanically interlocked with the body and at least a portion of the matrix is positioned circumferentially around at least a portion of the forward portion of the body.
E01C 23/12 - Devices or arrangements for working the finished surface; Devices for repairing the surface of damaged paving for taking-up, tearing-up, or breaking-up paving
Cutting elements include a carbonate diamond-bonded body that is sintered under HPHT conditions in the presence of a carbonate material, where the body includes a matrix phase of intercrystalline bonded diamond with interstitial regions including the carbonate material, where the diamond-bonded body is sintered without a substrate. A matrix casting is formed and mechanically coupled to the body after the body is sintered, and a portion of the body surface is exposed along a surface of the matrix casting. The exposed body surface is thereafter intentionally treated to induce a compressive residual surface stress that is greater than a remaining portion of the body. The compressive residual surface stress is less than about 500 MPa, and from about 100 to 500 MPa, and a remaining region the body may have a residual stress of less than about 300 MPa, and less than about 100 MPa.
A drill bit includes a bit body with high and low fluid pressure bodies. The low-ressure bit body includes a fixed cutting structure, and the high-pressure bit body includes at least one high-pressure fluid channel and nozzle capable of withstanding fluid pressures greater than 40 kpsi (276 MPa). A bottomhole assembly includes a drill bit with a bit body having fixed cutter and fluid jetting portions. Low and high-pressure channels in the bit body exit in the fixed cutter and fluid jetting portions. A high-pressure nozzle is coupled to the fluid jetting portion and the high-pressure fluid channel, and a plurality of fixed cutting elements are coupled to the fixed cutter portion. A pressure intensifier is coupled to the drill bit and is configured to increase a pressure of a fluid supplied to the high-pressure fluid channel in the bit body.
A cutting bit includes a bit body and high-pressure body with a high-pressure fluid conduit therethrough. The high-pressure body and bit body are joined together. The high-pressure fluid conduit is configured to convey a fluid at greater than 14.5 ksi, and in some embodiments greater than 40 ksi. The high-pressure fluid conduit may direct the fluid through a nozzle in a fluid jet to weaken material, such as an earth formation. The cutting bit includes at least one roller cone and/or blades with cutting elements thereon to remove the weakened material. A cutting bit includes both high and low-pressure fluid conduits, and high and low-pressure fluid nozzles. The high-pressure nozzles receive fluid flow from a downhole pressure intensifier, and a connection between the bit and the downhole pressure intensifier includes rigid connectors, flexible connectors, or a combination thereof.
A downhole tool includes a blade coupled to a body. The body and blade rotate about a longitudinal axis. A pre-formed faceplate is connected to the blade and partially defines a cutter pocket therein. Another portion of the cutter pocket is defined by the blade. The cutter pocket includes a sidewall and a base, with the sidewall formed by the blade and the pre-formed faceplate, and the base formed by the blade. The pre-formed faceplate includes a pre-formed hardfacing element. A downhole tool includes a blade coupled to a body. The body and blade rotate about a longitudinal axis. A pre-formed segment is connected to the blade and has a cutter pocket therein. The cutter pocket includes a sidewall and a base, and a cutting element is coupled to the pre-formed segment and within the cutter pocket. The pre-formed segment is optionally made of a different material than the blade and has increased wear and/or erosion resistance compared to the blade.
A downhole tool includes at least a pilot section, a first expansion section, and a second expansion section. The pilot section has a plurality of cutting elements to cut a pilot hole. Each of the expansion sections has a plurality of cutting elements to successively expand the pilot hole to achieve a final wellbore radius. The pilot section, first expansion section, and second expansion section each have one or more stabilizer pads on respective gages to stabilize the downhole tool during wellbore creation.
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
Polycrystalline diamond constructions are formed from a mixture of diamond grains including a first volume of fine-sized diamond grains, and a second volume of coarse-sized diamond grains. The fine-sized diamond grains are partially graphitized, and the coarse-sized diamond grains are not graphitized. The mixture of diamond grains is subjected to high pressure/high temperature sintering process conditions in the presence of a sintering aid thereby forming polycrystalline diamond. Contact areas between coarse-sized diamond grains in the polycrystalline diamond construction are substantially free of graphite.
A method of sintering a binderless cBN body includes providing a boron nitride particle mixture into a pressure chamber, the boron nitride particle mixture having a first type of boron nitride particles and boron nitride filler particles, and the boron nitride filler particles having a different size and/or type than the first type of boron nitride particles, and sintering the boron nitride particle mixture in the pressure chamber to form the cBN body by generating a pressure in the pressure chamber of less than 7.7 GPa and heating the boron nitride particle mixture to a temperature ranging from about 1900 °C to about 2300 °C, wherein the cBN body has a density of at least 97 percent.
C04B 35/583 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on borides, nitrides or silicides based on boron nitride
An anvil for use in a high pressure press includes a nose surface and a flank surface with a transition region therebetween. The transition region includes a continuous curve that may reduce stress risers in the anvil and/or in a gasket material during application of force in the high pressure press.
A cutting element may include a substrate; and an ultrahard layer on the substrate, the ultrahard layer including a non-planar working surface that is surrounded by a peripheral edge having a varying height around a circumference of the cutting element, the working surface also having: a plurality of cutting crests extending from an elevated portion of the peripheral edge across at least a portion of the working surface; at least one valley between the plurality of cutting crests; and a canted surface extending laterally from each of the outer plurality of cutting crests towards a depressed portion of the peripheral edge, a height between the depressed portion and the elevated portion being greater than a height between the elevated portion and the valley.
Polycrystalline diamond constructions comprise a diamond body attached with a substrate during high pressure/high temperature processing, and include a modified reaction zone interposed between the body and substrate that is engineered to minimize or eliminate unwanted back diffusion of carbon from the diamond body into the substrate during the high pressure/high temperature processing.
B24D 18/00 - Manufacture of grinding tools, e.g. wheels, not otherwise provided for
B24D 3/10 - Physical features of abrasive bodies, or sheets, e.g. abrasive surfaces of special nature; Abrasive bodies or sheets characterised by their constituents the constituent being used as bonding agent and being essentially inorganic metallic for porous or cellular structure, e.g. for use with diamonds as abrasives
E21B 10/46 - Drill bits characterised by wear resisting parts, e.g. diamond inserts
20.
POLYCRYSTALLINE DIAMOND CONSTRUCTIONS WITH PROTECTIVE ELEMENT
PCD constructions as disclosed comprise a ultra-hard body attached with a metallic substrate along a substrate extending between the body and the substrate. The construction includes a protective feature or element that is configured to protect a metal rich region or zone existing in the construction from unwanted effects of corrosion or erosion. The protective element extends from the body over the interface and along a portion of the substrate and may be integral with the body.
A cutting device for use in a drill bit has a body including an ultrahard material. The body has a top surface, a front surface, and at least one lateral surface adjacent the top surface. The lateral surface is oriented at a surface angle relative to the top surface between 30 and 150 degrees. One or more locking features are located on the lateral surface.
A cutting assembly for use in a drill bit has an ovoid insert including an ultrahard material. The ovoid insert is cast in a matrix such that the matrix surrounds at least part of the ovoid insert, limiting movement of the ovoid insert. Material is removed from the top surface and sidewall of the cutting assembly to produce a cutting edge.
A cutting element may include: a substrate; and an ultrahard layer on the substrate, the ultrahard layer having a non-planar working surface, the non-planar working surface being formed from a first region and a second region, the first region, encompassing at least a cutting edge or tip of the cutting element and having a differing composition than the second region.
A downhole cutting tool that includes a tool body, at least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face, and a top face extending between the cutting face and trailing face, a plurality of cutting elements attached to the at least one blade along the cutting face, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest. The at least two of the plurality of cutting elements on the at least one blade have differing material properties, sizes, orientations, and/or working surface geometries along a blade profile of the at least one blade.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
A downhole cutting tool that includes a tool body having a tool axis, at least one blade extending from the tool body including a cutting face, a trailing face, and a top face extending between the cutting face and the trailing face, a first cutting element attached to the at least one blade along the cutting face and a second cutting element attached to the at least one blade along the top face, rearward from and at the same radial position from the tool axis as the first cutting element. The working surface of each of the first and the second cutting elements has a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest. The first cutting element has a different size, orientation, geometry, or material properties from the second cutting element.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
A cutting bit includes a body, a plurality of blades, and at least one ultrahard insert cast directly into at least one of the plurality of blades. The ultrahard insert is positioned with a rear face directly contacting the blade.
Hardfacing material compositions comprise a plurality of hard material phases dispersed in a continuous metallic alloy binder phase, wherein the hard material phase comprises sintered carbide pellets and other carbide materials, wherein the pellets are encapsulated by thermally stable material layer formed from refractory metals or refractory carbides that that operate to insulate and protect the pellets from unwanted interdiffusion of constituent materials between the pellets and the metallic alloy binder phase during application of the hardfacing material composition onto a desired substrate to thereby retain a desired level of toughness and hardness to enhance operable service life.
Cutting elements and hardfacing materials as disclosed herein are in the form of a milled tooth having an uppermost first surface or crest and remaining surfaces such as flank surfaces and end surfaces extending downwardly away from crest. The crest has a hardfaced layer disposed thereon formed from a premium hardfacing material, and one or more of the remaining cutting element surfaces has a hardfaced layer formed from a hardfacing material different than the premium hardfacing material, wherein the hardfaced layer on the crest has a wear resistance at least 10 percent greater than that of the remaining cutting element hardfaced surfaces. The hardfaced layer on the crest may extend along a partial portion of one or more of the adjacent remaining cutting element surfaces.
A cutting element includes a pointed region having a side surface extending from a pointed region outer perimeter to a peak, an ultrahard material body forming a portion of the pointed region including the peak, and a base region extending a depth from the pointed region outer perimeter. The ultrahard material body has a height to width aspect ratio of greater than 3/4, the height defined between two points of the ultrahard material body having the greatest distance apart along a dimension parallel with a longitudinal axis of the cutting element, and the width defined between two points of the ultrahard material body having the greatest distance apart along a dimension perpendicular to the longitudinal axis.
A cutting element may include a substrate; and an ultrahard layer on the substrate, the substrate and the ultrahard layer defining a non-planar working surface of the cutting element such that the ultrahard layer forms a cutting portion and the substrate is at least laterally adjacent to the ultrahard layer.
A downhole cutting tool includes a body having a central axis extending therethrough, a plurality of blades extending outwardly from the body and converging towards a central region around the central axis, and at least one cutting element having a longitudinal axis, a non-cylindrical substrate, and an ultra-hard material body on the non-cylindrical substrate, the ultra-hard material body having a side surface extending around a cutting face and defining a cross-sectional shape of the ultra-hard material body, and the side surface comprising an edge having an inner angle of less than 180 degrees.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
32.
ERUPTION MINIMIZATION IN THERMALLY STABLE PCD PRODUCTS
A polycrystalline diamond construction may be made by subjecting diamond grains to a high pressure/high temperature condition in the presence of a catalyst material to form a polycrystalline diamond material comprising a matrix phase of bonded together diamond grains and interstitial regions disposed between the diamond grains including the catalyst material, treating the polycrystalline diamond material to remove the catalyst material therefrom to form a diamond body that is substantially free of the catalyst material, and attaching a substrate to the diamond body with a layer of eruption minimization material having a thickness from about 2 μm to 8 μm on at least one attachment interface surface of the substrate and/or diamond body.
A downhole cutting tool includes a tool body defining a cutter pocket and a rolling cutter having an inner rotatable cutting element and a sleeve in the cutter pocket, where axial movement of the inner rotatable cutting element is limited by an external retention element disposed outside of the sleeve.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
A cutting element includes a cutting end extending a depth from a cutting face to an interface surface opposite from the cutting face, and a spindle, the spindle axially separated from the cutting end by a transition region. The spindle has a spindle diameter measured between a spindle side surface, which is less than a cutting end diameter. A guide length, measured from a point of transition to the transition region to a retention feature, is longer than 75% of a total length of the spindle.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
A method for designing a drill bit includes assigning a score to cutting element arrangements that differ based on a design parameter, comparing the scores for different arrangements, and selecting the arrangement having the preferred or optimal score. The parameter may be, for example, the number of cutting elements in an array of cutting elements on a roller cone, the number of spiral sets in an array of a cutting elements, or the pitch between adjacent cutting elements in an array.
Cutting elements include a diamond-bonded body attached with a substrate. The substrate has a coercivity of greater than about 200 Oe, and has a magnetic saturation of from about 73 to 90. The diamond-bonded body has a compressive stress at the surface of greater than about 0.9 GPa after heat treatment, and greater than about 1.2 GPa prior to heat treatment.
A downhole cutting tool includes a body having at least 80 % of its volume made of at least one metallic region. The at least one metallic region includes a plurality of metallic particles in an infiltration binder. The infiltration binder has a melting temperature below the solidus temperature of the metallic particles. The at least one metallic region has a body hardness gradient extending at least 0.5 inches from a portion of an outer surface of the body to an interior portion of the metallic region, the body hardness gradient having a decreasing amount of carbon from the outer surface towards the interior portion. The downhole cutting tool also includes a plurality of cutting elements in cutting element pockets on the body.
A drill bit is used for drilling through earthen formations and forming a wellbore. The drill bit includes a bit body having a bit axis, and at least a first cone and a second cone coupled to the bit body. Each of the first and the second cones has a backface, a nose opposite the backface, and a cone axis of rotation. An array of cutting elements coupled to the first or second cones is in a band that lies between the backface and the nose. The cutting elements in the band are arranged at radial positions with respect to the bit axis and at least two adjacent cutting elements are at a same radial position within the array, and the remaining cutting elements are at different radial positions within the array.
A method includes simulating a cutting tool drilling an earth formation to determine cyclic loading on a cutting element disposed on the cutting tool and designing a test to subject a physical cutting element to physical cyclic loading corresponding to the simulated cyclic loading.
A method includes simulating a cutting tool drilling an earth formation by incrementally rotating the cutting tool at a plurality of time intervals, determining a true trajectory of a cutting element disposed on the cutting tool for the duration of the plurality of time intervals, and determining a dynamic work profile for the cutting element based on the true trajectory and a force acting on the cutting element at each time interval.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
A downhole tool includes a tool body, at least one blade with a front face having an undulating geometry including a plurality of ridges and valleys, and a top face facing outwardly from the tool body and transitioning to the front face at a cutting edge. At least one cutting element is in a pocket at the cutting edge. The at least one cutting element has a non-planar cutting face facing in the same direction as the front face. The non-planar cutting face has at least two sloping surfaces meeting at an elongated crest, valley, or other feature. A portion of the elongated feature adjacent the front face may substantially align with, and have substantially corresponding geometry as, a ridge or valley of the front face.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
42.
ASSEMBLIES FOR MAKING SUPERHARD PRODUCTS BY HIGH PRESSURE/HIGH TEMPERATURE PROCESSING
Assemblies as disclosed herein for making superhard products by HPHT process comprise a first can portion for accommodating a mixture of materials therein and a second can mated with the first can portion. A leak-tight seal is provided between the first can portion and second can portion in a manner that accommodates the manufacture of relatively longer superhard products without having to change other elements or members used for HPHT processing to thereby provide improved manufacturing flexibility and cost efficiency.
A drill bit for use with a drilling tool, such as a handheld rotary hammer tool. The drill bit includes a shank and an ultra-hard cutting element coupled to the shank. At least a portion of an outer surface of the ultra-hard cutting element includes an ultra-hard abrasive material. The ultra-hard cutting element includes at least one flute. The ultra-hard abrasive material may be polycrystalline diamond or polycrystalline cubic boron nitride. The drill bit may also include one or more lips extending radially across at least a portion of the outer surface.
B28D 1/14 - Working stone or stone-like materials, e.g. brick, concrete, not provided for elsewhere; Machines, devices, tools therefor by boring or drilling
A method of manufacturing a component for use in a high pressure press includes successively depositing a volume of one or more materials using a deposition device to build a three dimensional body of the component having a selected material property varied along at least one direction of the component for use in the high pressure press.
B22F 5/00 - Manufacture of workpieces or articles from metallic powder characterised by the special shape of the product
B22F 7/04 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite layers with one or more layers not made from powder, e.g. made from solid metal
A method of forming a mold used to manufacture downhole tools includes depositing successive layers of a material mixture and an adhesive using an automated layering device according to a computer aided pattern, the material mixture including a first composition and a second composition, the first composition having at least a different shape, size, or chemical composition than the second composition, at least one of the first composition or the second composition being granulated.
B22F 5/00 - Manufacture of workpieces or articles from metallic powder characterised by the special shape of the product
B22F 7/02 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite layers
B22F 3/105 - Sintering only by using electric current, laser radiation or plasma
B33Y 70/00 - Materials specially adapted for additive manufacturing
B33Y 80/00 - Products made by additive manufacturing
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
46.
CUTTING ELEMENTS AND DRILL BITS INCORPORATING THE SAME
An ultra-hard cutting element for use in a drill bit, such as a percussion drill bit, a rotary cone drill bit, a drag bit, or a reamer. The ultra-hard cutting element includes a base portion, an extension portion on an end of the base portion, and a lip on an outer surface of the extension portion. At least a portion of the outer surface of the extension portion includes an ultra-hard abrasive material. The ultra-hard abrasive material may be polycrystalline diamond or polycrystalline cubic boron nitride.
A drill bit includes a bit body having a pin end capable of attaching to a drill string, a cutting end having a plurality of blades extending radially therefrom and separated by a plurality of channels therebetween, and a fluid plenum open to receiving drilling fluid from the drill string. The drill bit further includes a cutting element in a cutter pocket formed on the plurality of blades, a fluid flow passageway extending from the fluid plenum to at least one nozzle bore, a nozzle attached to the nozzle bore and having a nozzle face spaced apart from the bit body, and a protruding body having an transition surface extending from the bit body to proximate the nozzle face. A width of the protruding body varies along a height of the protruding body from proximate the bit body to proximate the nozzle face.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/60 - Drill bits characterised by conduits or nozzles for drilling fluids
48.
DRILL BITS WITH CORE FEATURE FOR DIRECTIONAL DRILLING APPLICATIONS AND METHODS OF USE THEREOF
A drill bit for obtaining core sample fragments from a subterranean formation includes a bit body having a bit centerline and a bit face, a plurality of blades extending radially along the bit face, including a coring blade, a plurality of cutting elements on the blades, and a non-planar insert embedded in the bit body proximate the bit centerline. One of the cutting elements is a first cutting element on the coring blade at a first radial position from the bit centerline, and at least a portion of the coring blade is radially outward from a most radially interior cutting part of the first cutting element.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
49.
POLYCRYSTALLINE DIAMOND CONSTRUCTIONS WITH ENHANCED SURFACE FEATURES
Polycrystalline diamond (PCD) constructions and cutting elements include a PCD body having a composite layer with a number of PCD particles dispersed in a surrounding PCD matrix. The composite layer has a wear surface including asperities projecting outwardly therefrom, where the asperities are formed from the PCD particles. In an embodiment, the asperities enhance the efficiency of breaking rock during a drilling operation. The body includes one or more PCD transition layers between the composite layer and a metallic substrate attached to the diamond-bonded body. The one or more transition layers may have a hardness that is the same or less than the hardness of the composite layer.
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
50.
SOLID PCD WITH TRANSITION LAYERS TO ACCELERATE FULL LEACHING OF CATALYST
A method of making a polycrystalline diamond compact includes forming a first layer of polycrystalline diamond precursor materials comprising diamond particles and a first concentration of catalyst, forming a second layer of polycrystalline diamond precursor materials comprising diamond particles and a second concentration of catalyst, and placing a layer of an infiltrant material in the proximity of the first or the second layer of polycrystalline diamond precursor materials. The second concentration of catalyst is greater than the first concentration of catalyst. The infiltrant material is a catalyst. The first layer and the second layer are sintered under high-pressure high-temperature conditions in the presence of the infiltrant material to form the polycrystalline diamond compact. At least a portion of the catalyst is leached from the polycrystalline diamond compact.
B22F 5/00 - Manufacture of workpieces or articles from metallic powder characterised by the special shape of the product
B22F 7/04 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite layers with one or more layers not made from powder, e.g. made from solid metal
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
51.
POLYCRYSTALLINE DIAMOND SINTERED/REBONDED ON CARBIDE SUBSTRATE CONTAINING LOW TUNGSTEN
A method of forming a polycrystalline diamond cutting element includes assembling a diamond material, a substrate, and a source of catalyst material or infiltrant material distinct from the substrate, the source of catalyst material or infiltrant material being adjacent to the diamond material to form an assembly. The substrate includes an attachment material including a refractory metal. The assembly is subjected to a first high-pressure/high temperature condition to cause the catalyst material or infiltrant material to melt and infiltrate into the diamond material and subjected to a second high-pressure/high temperature condition to cause the attachment material to melt and infiltrate a portion of the infiltrated diamond material to bond the infiltrated diamond material to the substrate.
A downhole cutting tool includes a tool body, a plurality of blades extending a height from the tool body to an outermost surface, and a plurality of cutting elements on at least one of the plurality of blades, each cutting element having a longitudinal axis oriented substantially radially outward from the outermost surface of the blade, and at least two adjacent cutting elements of the plurality of cutting elements having different axial lengths.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
53.
ULTRA-HARD MATERIAL CUTTING ELEMENTS AND METHODS OF MANUFACTURING THE SAME WITH A METAL-RICH INTERMEDIATE LAYER
Methods for joining an ultra-hard body, such as a thermally stable polycrystalline diamond (TSP) body, to a substrate and mitigating the formation of high stress concentration regions between the ultra-hard body and the substrate. One method includes covering at least a portion of the ultra-hard body with an intermediate layer, placing the ultra-hard body and the intermediate layer in a mold, filling a remaining portion of mold with a substrate material including a matrix material and a binder material such that the intermediate layer is disposed between the ultra-hard body and the substrate material, and heating the mold to an infiltration temperature configured to melt the binder material and form the substrate.
B22F 7/06 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools
B22F 5/00 - Manufacture of workpieces or articles from metallic powder characterised by the special shape of the product
Systems capable of seismically investigating the earth can include one or more seismic sources and one or more seismic sensors located on the surface and/or included on a drill string. The seismic sources can include vibratory tools such as a vibratory hammer capable of improving rate of penetration of the drill string into a formation, and/or a vibratory agitator capable of reducing or breaking friction developed within the wellbore. Related methods can include using vibratory tools included in a drill string in seismic investigations, such as while the drill string is on-bottom or off-bottom.
A cutting element assembly for a drill bit includes a housing, an inner rotatable cutting element, and a pre-load assembly. The inner rotatable cutting element has a cutting end and a portion that is retained in the housing. A base of the cutting end and an end of the housing act as radial bearing surfaces. The pre-load assembly is between the radial bearing surfaces.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
56.
A GRAPHITE HEATER WITH TAILORED RESISTANCE CHARACTERISTICS FOR HPHT PRESSES AND PRODUCTS MADE THEREIN
A method for sintering includes loading a tool material into a resistance heating element within a HPHT press and heating the resistance heating element at a first axial portion to a control temperature, where a temperature difference is measured between the control temperature and a second temperature measured at a distal axial portion along the resistance heating element, wherein a difference between the control temperature and the second temperature ranges between about 5 percent to about 11 percent of the control temperature.
Roller cutters comprise a diamond-bonded body joined to an infiltration substrate. An extension is joined to the substrate and includes first section having a diameter sized the same as the substrate, and an integral second section having a diameter smaller than the substrate. The extension is joined to the substrate during an HPHT process. The first section has a thickness greater than that of the infiltration substrate. The second section has an axial length greater than the combined thickness of the substrate and the first section. The extension has a strength and/or toughness greater than the substrate as a result of its material composition, e.g., the amount of binder phase material and/or the size of hard phase material. The roller cutter is rotatably disposed within a pocket internal cavity, wherein the pocket is attached to a drill bit.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
A method for manufacturing a drill bit includes coupling displacements to a mold with a series of attachment members, filling a cavity of the mold with a material, and heating the material to form a bit body of the drill bit. The method may also include removing the displacements to expose cutter pockets in the bit body and coupling cutting elements to the cutter pockets.
B22F 7/06 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools
B22F 5/00 - Manufacture of workpieces or articles from metallic powder characterised by the special shape of the product
A method of manufacturing a polycrystalline diamond construction includes placing diamond powder in a reaction container, placing a layer of a ceramic powder or an inert metal having a melting temperature greater than 1600°C in powdered form on top of the diamond powder in the reaction container, the layer of the ceramic powder or inert metal powder extending across the entire inner diameter of the reaction container, placing additional diamond powder on top of the layer of ceramic powder or inert metal powder in the reaction container, placing a substrate material into the reaction container on top of the additional diamond powder, and subjecting the reaction container and its contents to high temperature, high pressure sintering conditions.
A method of making a flux-coated binder includes treating metal binder slugs to have an adherent surface, adding a flux powder to the treated metal binder slugs, and distributing the flux powder on the adherent surface of the metal binder slugs.
B22F 1/02 - Special treatment of metallic powder, e.g. to facilitate working, to improve properties; Metallic powders per se, e.g. mixtures of particles of different composition comprising coating of the powder
B22F 9/00 - Making metallic powder or suspensions thereof; Apparatus or devices specially adapted therefor
A downhole cutting tool may include tool body; a first blade extending from the tool body; a plurality of cutting elements attached to the first blade, the plurality of cutting elements comprising at least two types of cutting elements, wherein the first blade extends from the tool body to a first height adjacent a first type of cutting element and a second height, different from the first height, adjacent a second type of cutting element.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
62.
HYDRAULIC FRACTURING WHILE DRILLING AND/OR TRIPPING
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Brown, James Ernest
Utter, Robert J.
Cooper, Ian M.
Miller, Matthew J.
Potapenko, Dmitriy Lvanovich
Abstract
Methods and apparatuses for hydraulically fracturing a subterranean wellbore while drilling and/or tripping are disclosed. A method for hydraulically fracturing a subterranean formation may include rotating a drill string to drill the wellbore and hydraulically fracturing the subterranean formation at a plurality of axially spaced locations along the wellbore while tripping the drill string out of the wellbore. The drill string may include a hydraulic fracturing assembly. The hydraulic fracturing operation may include translating the drill string in an uphole direction so that a set of frac ports in the hydraulic fracturing assembly is adjacent a region of the formation selected for fracturing, expanding at least one pair of packers to seal an annular region of the wellbore exterior to the frac ports, and pumping fracturing fluid downhole through the frac ports to hydraulically fracture the subterranean formation.
Implementations of the present disclosure relate to apparatuses, systems, and methods for automated hardfacing of a surface. The automated hardfacing of a surface may include securing tiles of a superhard material on a surface, applying hardfacing material around the tiles, and fusing the hardfacing material using a thermal energy source. The thermal energy source and the assembly of the surface, hardfacing material, and tiles may be moved automatically relative to one another according to a pattern.
B22F 3/105 - Sintering only by using electric current, laser radiation or plasma
E21B 10/46 - Drill bits characterised by wear resisting parts, e.g. diamond inserts
C21D 1/09 - Surface hardening by particle radiation
C21D 9/22 - Heat treatment, e.g. annealing, hardening, quenching or tempering, adapted for particular articles; Furnaces therefor for machine cutting tools
C21D 10/00 - Modifying the physical properties by methods other than heat treatment or deformation
B22F 7/06 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools
Milling systems, tools, and methods include using a mill with secondary attrition system to re-mill cuttings and other debris away from the face of the mill. The secondary attrition system may be located uphole of the mill may be used to stage conditioning and re-sizing of debris. After debris is generated by the mill, the secondary attrition system may re-mill the debris to a finer size before allowing the debris to pass out of the sleeve. The debris may be re-milled by secondary cutting elements while within an annular gap positioned radially between the sleeve and a drive shaft for the mill. The annular gap may have a variable width as a result of a tapered outer surface of the drive shaft and/or a tapered inner surface of the sleeve. The variable width may cause debris to be re-milled into increasingly finer sizes.
E21B 29/00 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
E21B 41/00 - Equipment or details not covered by groups
A mill includes a barrier to promote re-circulation of debris and cuttings to the face of the mill. The face of the mill may include cutting elements. A barrier may obstruct the flow of cuttings and debris away from the face to re-circulate the cutting and debris to promote re-milling of the cuttings and debris by the cutting elements of the face of the mill. The barrier may include a hydraulic barrier formed by fluid expelled from nozzles in or above the mill. A secondary attrition system uphole of the mill may also be used to stage conditioning and re-sizing of cuttings and debris. After debris and cuttings pass through the barrier, the secondary attrition system may re-mill the cuttings and debris to a finer size before allowing the cuttings and debris to pass into the wellbore annulus for transport to the surface.
E21B 29/00 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
E21B 10/60 - Drill bits characterised by conduits or nozzles for drilling fluids
A tool with a hydraulic lock mechanism may include a body defining a flow tube and a chamber. An expandable member may be coupled to the body. A first valve may be located between the chamber and the flow tube to control the flow of fluid into the chamber from the flow tube. A second valve may located between the chamber and an external environment to control the flow of fluid from the chamber into the external environment. The first and second valves may trap fluid within the chamber to maintain the tool in an active position. A piston may be connected to the expandable member and may move in response to pressurization of the chamber. At one position, the piston may cause the expandable member to extend to a radially outward position. At another position, the piston may cause the expandable member to retract to a radially inward position.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 34/06 - Valve arrangements for boreholes or wells in wells
An expandable tool includes a body and a recess extending at least partially through the body from an outer radial surface of the body. A spline insert may be at least partially positioned in the recess and coupled to the body. The spline insert may include a single spline or multiple splines. A cutter block or other expandable member may be at least partially positioned in the recess. The cutter block or other expandable member may include a spline on a side surface thereof, which spline may be engaged with the one or more splines of the spline insert. Engagement between one or more splines of the spline insert and spline of the cutter block or other expandable member may allow the expandable member to move radially outward from a retracted position to an expanded position, and vice versa.
A sensor assembly may include a housing made of a non-magnetic material. The housing may define an interior chamber. A shaft may extend from the housing. A bearing may be positioned around the shaft. An impeller may be positioned around the shaft and the bearing, and the impeller may include a magnetized portion. A sensor may be positioned within the interior chamber and/or proximate the magnetized portion. The sensor may detect the magnetized portion of the impeller to sense a rate of rotation of the impeller. The rate of rotation of the impeller may correspond to changes in flow rate of the fluid. As the flow rate of the fluid, and the rate of rotation of the impeller change in predetermined manners, control signals may be conveyed to activate a tool.
G01F 1/10 - Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects using rotating vanes with axial admission
Drilling flow control tools may include a tool body having a central bore and bypass ports that allow flow of fluid to an outer surface of the tool body. The drilling flow control tool may also include a control sleeve within the central bore. The control sleeve may restrict fluid flow through the bypass ports when in an inactive state and allow the fluid flow through the bypass ports when in an active state. The drilling flow control tool may further include a release subassembly movably coupled to the tool body. Packer cups coupled to the tool body can act as packoff devices that control passage of fluid along the outer diameter of the tool body. Using the packer cups and control sleeve, fluid flow may be circulated within an inner annulus of a wellbore, an outer annulus of a wellbore, or both.
A method for selecting a bottomhole assembly (BHA) includes inputting BHA parameters, wellbore parameters, and drilling operating parameters, performing a dynamic simulation of a first BHA based on the BHA parameters, wellbore parameters, and drilling operating parameters, and presenting a wellbore quality factor of the first BHA calculated from the dynamic simulation.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
G06F 19/00 - Digital computing or data processing equipment or methods, specially adapted for specific applications (specially adapted for specific functions G06F 17/00;data processing systems or methods specially adapted for administrative, commercial, financial, managerial, supervisory or forecasting purposes G06Q;healthcare informatics G16H)
71.
CASING AND LINER DRILLING CASING CLUTCH AND SWIVEL SUB
A method of drilling and cementing a wellbore, wherein the method provides a tool with a bit on a drillstring, drilling the drillstring into a geological stratum with the bit, at a total depth of the wellbore, unlocking a sub in the drillstring and pumping and placing a cementitious material into the drillstring and through a cement port in the drillstring while rotating at least a portion of the drill string, wherein a shoe of the drill string remains static.
A downhole tool including a body coupled to a stabilizer and an underreamer. The stabilizer may include a blade that moves from a retracted position to an expanded position. The underreamer may include a cutter block that moves from a retracted position to an expanded position. The underreamer is positioned above the stabilizer, and a distance between an outer surface of the cutter block and a central longitudinal axis of the body may be greater than a distance between an outer surface of the blade and the central longitudinal axis when the blade and cutter block are in the expanded positions.
E21B 10/26 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
E21B 7/28 - Enlarging drilled holes, e.g. by counterboring
73.
SYSTEMS AND METHODS FOR ACTIVATING A DOWNHOLE TOOL
A downhole tool may include a body with a flow channel therethrough. The flow channel may be an outer flow channel that is radially outward relative to an inner flow channel and/or a rod. The rod or inner flow channel may act as a valve to allow flow within the outer flow channel. A plunger may be positioned within the body and acted upon by fluid in the inner flow channel or the rod. The plunger may move from a first position that restricts fluid flow from the outer flow channel to a chamber in the body to a second position that allows fluid flow from the outer flow channel to the chamber in the body at least partially in response to fluid flowing through the inner flow channel. An expandable member, such as a cutting tool or isolation tool, may be movably coupled to the body.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 34/06 - Valve arrangements for boreholes or wells in wells
A tool including a body defining a pocket, a cutting element in the pocket, at least one projection between an outside surface of the cutting element and an inside surface of the pocket, and a braze material between the cutting element and the pocket fixing the cutting element to the pocket.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
75.
METHODS FOR ANALYZING AND OPTIMIZING CASING WHILE DRILLING ASSEMBLIES
A method for selecting a bottomhole assembly (BHA) includes inputting casing while drilling BHA parameters, wellbore parameters, and casing while drilling operating parameters, performing a dynamic simulation of a first BHA based on the casing while drilling BHA parameters, wellbore parameters, and casing while drilling operating parameters, and presenting a first set of performance data of the first BHA calculated from the dynamic simulation.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
G06F 9/455 - Emulation; Interpretation; Software simulation, e.g. virtualisation or emulation of application or operating system execution engines
G06F 19/00 - Digital computing or data processing equipment or methods, specially adapted for specific applications (specially adapted for specific functions G06F 17/00;data processing systems or methods specially adapted for administrative, commercial, financial, managerial, supervisory or forecasting purposes G06Q;healthcare informatics G16H)
76.
PRESSURE PUMPING VALVES AND METHODS OF MAKING SUCH VALVES
A method for joining a valve member for use within a valve, the method including brazing a body portion having a head and a base, the base having a bore extending a depth therein, to a leg portion having a shaft, the shaft having a distal end, a proximal end opposite the distal end, and a plurality of legs extending radially and axially therefrom and away from the proximal end, the brazing including placing a braze material between the bore and the proximal end, inserting the proximal end into the bore such that a portion of an outer surface of the proximal end is adjacent to an inner surface of the bore, and heating at least the adjacent surfaces to a braze temperature.
Repeated percussive forces may be provided using various devices, systems, assemblies, and methods. Example rotary percussive devices may be used in a downhole environment, including within a drilling system that includes a percussive hammer drill bit. The rotary percussive device may include a rotational translator to convert drilling fluid pressure into a rotational force. An axial translator coupled to the rotational translator may convert the rotational force into an axial percussive force. This conversion may be done using magnets arranged in arrays of alternating polarities. The rotational translator may longitudinally overlap the axial translator. The rotational translator may include a rotational stator rotationally fixed within a bottomhole assembly. The rotational stator may include a shaft of a positive displacement motor.
A downhole cutting apparatus includes a tubular body and a cutter block extending radially therefrom. The cutter block includes at least one row of cutting elements. The row or cutting elements defines a cutting profile having a first underreaming cutting edge, a second underreaming cutting edge, and a first backreaming cutting edge between the first underreaming cutting edge and the second underreaming cutting edge.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
79.
CUTTING STRUCTURE WITH BLADE HAVING MULTIPLE CUTTING EDGES
A downhole cutting apparatus includes a cutter block having a longitudinal blade. The longitudinal blade includes a first cutting edge adjacent a second cutting edge, and the first cutting edge and the second cutting edge are both either underreaming cutting edges, backreaming cutting edges, or a combination of underreaming and backreaming cutting edges.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
Polycrystalline cubic boron nitride includes cubic boron nitride grains and AlB12 between the cubic boron nitride grains. A method of manufacturing heat-treated polycrystalline cubic boron nitride includes sintering a mixture including cubic boron nitride and aluminum metal powder to form polycrystalline cubic boron nitride, and heat-treating the polycrystalline cubic boron nitride to form the heat-treated polycrystalline cubic boron nitride. A method of manufacturing polycrystalline cubic boron nitride includes sintering a mixture including cubic boron nitride and aluminum metal powder, the mixture including the cubic boron nitride in an amount of 85 vol% to 95 vol% and the aluminum metal powder in an amount of 5 vol% to 15 vol%, based on the total volume of the mixture.
C04B 35/583 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on borides, nitrides or silicides based on boron nitride
C04B 35/5831 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on borides, nitrides or silicides based on boron nitride based on cubic boron nitride
C04B 35/5833 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on borides, nitrides or silicides based on boron nitride based on hexagonal boron nitride
81.
SINGLE-TRIP CASING CUTTING AND BRIDGE PLUG SETTING
A downhole tool may include a bridge plug releasably coupled to a casing cutting tool. The bridge plug may be set within a wellbore and the casing cutting tool may be used in a milling or perforating operation during a single downhole trip of the downhole tool. A method for using a downhole tool may include setting the bridge plug in a wellbore and performing a casing cutting operation during a same downhole trip. The casing cutting tool may be a section mill and a section milling operation may be performed before or after uncoupling the bridge plug from the section mill while downhole. The section milling operation may remove an entire portion of casing within a region of the wellbore for receiving a cement plug. The casing cutting too may be a perforation tool and perforating may be used to remove portions of casing.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 29/00 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
82.
CUTTING ELEMENTS HAVING NON-PLANAR SURFACES AND DOWNHOLE CUTTING TOOLS USING SUCH CUTTING ELEMENTS
A cutting element may include a substrate, an upper surface of the substrate including a crest, the crest transitioning into a depressed region, and an ultrahard layer on the upper surface, thereby forming a non-planar interface between the ultrahard layer and the substrate. A top surface of the ultrahard layer includes a cutting crest extending along at least a portion of a diameter of the cutting element, the top surface having a portion extending laterally away from the cutting crest having a lesser height than a peak of the cutting crest.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
A multi-stage flow sub usable in wellbore operations provides for flow of fluid from a tool string to a wellbore annulus, and may provide for one or more of controlling wellbore pressure during a tool operation, or preventing stripping of wet string. The multi-stage flow sub may include a housing having an axial bore and at least one flow passage. A sleeve within the housing may have an axial bore, a shoulder acting as a ball seat, and first and second axially offset flow passages. A first burst disc may be in fluid communication with the first flow passage, and a second burst disc may be in fluid communication with the second flow passage, the second burst disc having a higher burst pressure than the first burst disc.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Moffitt, Michael Eric
Abstract
A liner drilling system and method to at least partially drill a wellbore with a liner and cement the liner in place in the wellbore, all in a single downhole trip.
A method of manufacturing a drill bit may include inserting an attachment end of a journal portion into a cavity of a blade portion. The journal portion includes the attachment end; a journal end opposite from the attachment end; and a journal on the journal end extending downward and radially outward from a longitudinal axis of the journal portion. The blade portion includes the cavity extending a distance into the blade portion; and at least one blade extending along the blade portion from adjacent to the cavity to a gauge region of the drill bit. Then, the method includes attaching the journal portion to the blade portion and mounting a roller cone to the journal.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Huang, Sujian
Liu, Xinghan
Yang, Jianjun
Xu, Gang
Feng, Feng
Abstract
Specialized computing systems, devices, interfaces and methods facilitate the simulation of downhole wellbore re-entry procedures such as sidetracking, rat hole extension, hole enlargement, window modification, fishing, and other re-entry procedures. Computing systems, devices, interfaces and methods enable a user to design and select BHA components and procedures to be compared and simulated. Various re-entry parameters, such as re-entry tool parameters, whipstock parameters, wellbore casing parameters, window parameters, rat hole parameters, and the like may be accessed and selectably modified with re-entry and simulation interfaces to define and control the simulated re-entry procedures. Different types of output are selectably rendered to reflect various aspects of the simulated re-entry procedures.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
G06G 7/48 - Analogue computers for specific processes, systems, or devices, e.g. simulators
G06G 3/10 - Devices in which the computing operation is performed mechanically for simulating specific processes, systems, or devices
87.
COMPUTING SYSTEMS, TOOLS, AND METHODS FOR SIMULATING WELLBORE ABANDONMENT
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Huang, Sujian
Liu, Xinghan
Yang, Jianjun
Xu, Gang
Feng, Feng
Abstract
Specialized computing systems, devices, interfaces and methods facilitate the simulation of downhole wellbore abandonment procedures such as section milling and casing milling. Computing systems, devices, interfaces and methods enable a user to design and select BHA components and procedures to be compared and simulated. Various parameters, such as wellbore casing parameters, milling tool parameters, simulation parameters, and the like may be accessed and selectably modified by user input with interactive elements presented at user interfaces to define and control simulations of abandonment procedures. Different types of output are selectably rendered to reflect various aspects of the simulated abandonment procedures.
G06G 7/48 - Analogue computers for specific processes, systems, or devices, e.g. simulators
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
G06G 3/10 - Devices in which the computing operation is performed mechanically for simulating specific processes, systems, or devices
A method of forming a cutting element may include subjecting a first press containing at least a diamond powder-containing container and a volume of a high melting temperature non-reactive material to a first high pressure high temperature sintering condition to form a sintered polycrystalline diamond wafer including a diamond matrix of diamond grains bonded together and a plurality of interstitial spaces between the bonded together diamond grains; and subjecting a second press containing the sintered polycrystalline diamond wafer and a substrate to a second high temperature high pressure condition, thereby attaching the wafer to the substrate to form a cutting element having a polycrystalline diamond layer on the substrate.
B22F 7/06 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools
89.
CHEMICAL LEACHING/THERMAL DECOMPOSING CARBONATE IN CARBONATE PCD
A method for treating a polycrystalline diamond material includes subjecting the polycrystalline diamond material to a leaching process and to a thermal decomposition process.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Huang, Sujian
Liu, Xinghan
Yang, Jianjun
Xu, Gang
Feng, Feng
Abstract
Specialized computing systems, devices, interfaces and methods facilitate the simulation of downhole milling procedures such as wellbore departure milling procedures. Computing systems, devices, interfaces and methods enable a user to design and select milling components and procedures to be compared and simulated. Various milling parameters, such as milling tool parameters, whipstock parameters, and wellbore casing parameters may be accessed and selectably modified with milling and simulation interfaces to define and control the simulated milling procedures. Different types of output are selectably rendered to reflect various aspects of the simulated milling procedures.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
G06G 7/48 - Analogue computers for specific processes, systems, or devices, e.g. simulators
G06G 3/10 - Devices in which the computing operation is performed mechanically for simulating specific processes, systems, or devices
An apparatus for forming a cutting insert may include a compression device having a sleeve with a bore. The sleeve may receive a substantially hollow can. Solid particulates may be positioned within the can, and a substrate material or other punch may also be positioned in the can. A forming device adjacent an end of the can in which the solid particulates are located may include at least one protrusion extending into the bore. The protrusion may be adapted to deform the can while also forming the plurality of solid particulates into a solid mass having one or more reliefs and/or lobes. A method may include pressing the solid particulates while within a can to form a solid mass having one or more reliefs or lobes. An HPHT process may be performed to bond the solid mass to a substrate material.
B22F 7/06 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Mahajan, Manoj D.
Brietzke, Daniel W.
Fuller, Nathan E.
Barnhouse, James A.
Ishak, Georges
Abstract
An underreamer for increasing the diameter of a bore. The underreamer includes a substantially cylindrical body. A mandrel may extend axially through the body. One or more cutter blocks are movably coupled to the body. A ratio of a height of the cutter block to a diameter of the body is between about 0.35:1 and about 0.50:1.
E21B 10/26 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
E21B 7/28 - Enlarging drilled holes, e.g. by counterboring
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Xia, Sike
Deng, Xin
Balasubramanian, Nagarajan
Abstract
A downhole tool includes a tool body and at least one blade coupled to the tool body. Cutting elements are coupled to a forward surface of the blade, and each cutting element may include a flank face and a trailing face to collectively define the width of the cutting element. A cutting edge is formed at the intersection of the flank face and a front face of the cutting element. The trailing and flank faces of adjacent cutting elements may be inclined relative to each other to define a flank angle that may be between greater than 0 and 15. Adjacent cutting elements may have a gap therebetween, even when there is contact between the adjacent cutting elements.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
94.
HYDRAULICALLY ACTUATED TOOL WITH ELECTRICAL THROUGHBORE
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Nagaraj, Mahavir
Aubin, John M.
Pereira, Renato
Pendse, Bhushan
Vaghi, Francesco
Abstract
A bottom hole assembly includes a drill string, a bit coupled to an end of the drill string, a rotary steerable system coupled to the drill string above the bit, a hydraulically actuated tool assembly coupled to the drill string above the rotary steerable system, and an electrically controlled tool coupled to the drill string above the hydraulically actuated tool assembly and electrically coupled to the rotary steerable system. A method includes running a bottom hole assembly downhole, the bottom hole assembly including a drill bit, a rotary steerable system, an electrically controlled tool, and a hydraulically actuated tool assembly disposed between the rotary steerable system and the electrically controlled tool. The method includes cutting a formation with the drill bit, actuating the hydraulically actuated tool assembly, and maintaining an electrical connection between the rotary steerable system and the electrically controlled tool during the running, the cutting, and the actuating.
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
E21B 7/28 - Enlarging drilled holes, e.g. by counterboring
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Eriksen, Erik P.
Abstract
Apparatuses and methods for retrieving a tool or bottom hole assembly. The apparatus may include a latching device that couples to a tool or bottom hole assembly to be retrieved and at least one seal extending radially from the apparatus to engage an inner diameter of a tubular, such as a casing string. A pump inlet is disposed in or through an outer surface of the apparatus uphole of the at least one seal. A pump outlet is disposed in or through an outer surface of the apparatus downhole of the at least one seal. The apparatus may also include a pump for pumping a drilling fluid from the pump inlet to the pump outlet in order to generate a differential pressure across the at least one seal and provide a hydraulic force to effect retrieval of the tool or bottom hole assembly.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Salvo, Vincente S.
Stewart, Michael
Xia, Sike
Ishak, Georges
Abstract
A downhole tool has a body with a bore formed at least partially therethrough. A cutter block may be coupled to the body and move radially outward from the body in response to an increased pressure in the bore. The cutter block may include an outer surface that transitions from a first portion to a second portion, with the first portion being downhole of the second portion. A radius of curvature between the first and second portions may be less than about 7 cm. The second portion or a line tangential thereto may be oriented at an angle from about 60° to about 120° with respect to a central longitudinal axis of the body. A plurality of cutting elements may be disposed on the outer surface of the cutter block. At least one of the cutting elements may be disposed at least partially on the first or second portion of the outer surface.
E21B 10/26 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/62 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Mohon, Brian
Costo, Robert J.
Doud, Brian
Luong, Phuc Truong
Abstract
A pressure pulse generating tool may include an upper valve assembly disposed within the bore of a housing, where the upper valve assembly is configured to allow a fluid to flow through the upper valve assembly when in an open state. The upper valve assembly may also be configured to restrict the fluid from flowing through the upper valve assembly when in a closed state. The pressure pulse generating tool may further include a lower valve assembly disposed within the bore of the housing, where the lower valve assembly is configured to receive the fluid flow from the upper valve assembly. The lower valve assembly may also be configured to separate from the upper valve assembly in response to an increase in fluid pressure in an annulus defined between the upper valve assembly and the housing.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
SCHLUMBERGER TECHNOLOGY B.V. (Netherlands)
Inventor
Easter, Phil Philip
Burkhard, Alan Wayne
Abstract
A fluid control system has a body with the inlet passage in fluid communication with a discharge passage. The position of a choke piston in the body controls flow of the fluid from the inlet passage to the discharge passage. A controller connected to the body has an actuator connected to a linkage that is connected to the choke piston. The controller positions the choke piston in the body using the actuator and the linkage to control the flow of a fluid from the inlet passage to the outlet passage.
A cutting element may include a substrate including a plurality of metal carbide particles and a first metal binder having a first metal binder content; an outer layer of polycrystalline diamond material at an end of the cutting element, the polycrystalline diamond material including a plurality of interconnected diamond particles; and a plurality of interstitial regions disposed among the interconnected diamond particles, the plurality of interstitial regions containing a second metal binder having a second metal binder content. The cutting element also includes at least one transition zone between the substrate and the outer layer, the at least one transition zone including a plurality of refractory metal carbide particles and a third metal binder having a third metal binder content, the third metal binder content being less than the first metal binder content and the second metal binder content.
PRAD RESEARCH AND DEVELOPMENT LIMITED (Virgin Islands (British))
Inventor
Yang, Baozhong
Ray, Tommy G.
Hu, Jianbing
Su, Zhenbi
Terracina, Dwayne P.
Hu, Xin
Abstract
Various implementations described herein are directed to a vibration tool, e.g., for use in drilling. In one implementation, the vibration tool may include a housing having a bore extending therethrough. The vibration tool may also include a piston subassembly positioned inside the bore, where the piston subassembly is configured to oscillate when fluid flow inside the piston subassembly exceeds a predetermined flow rate. The vibration tool may further include a valve mechanism positioned around the piston subassembly, where the valve mechanism is configured to restrict fluid to flow inside the piston subassembly when the valve mechanism is in a closed state and configured to allow the fluid to flow from the piston subassembly to the bore when the valve mechanism is in an open state.
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