PATENTS

US 5119892

“Rotary Drill Bits” June 9, 1992

A rotary drill bit comprises a bit body having a shank for connection to a drill string and a passage for supplying drilling fluid to the face of the bit, which carries a plurality of polycrystalline diamond preform cutting elements. The cutting elements on one side of a diameter of the bit have positive side rake and the cutting elements on the other side of the diameter have negative side rake so that the vectorial sum of the reaction forces between the formation being drilled and the cutting elements provides a resultant lateral imbalance force acting on the bit body as it rotates in use. The gauge of the bit body includes low friction bearing pads so located as to transmit the resultant lateral force to the sides of the borehole. Since the bearing pads are of low friction, they slide around the surface of the formation and any tendency for bit whirl to be initiated is reduced. The lateral imbalance force may also be provided by varying the back rake of the cutting elements on different parts of the bit, or by including an asymmetrical mass of material in the bit body.

US 5163524

“Rotary Drill Bits” November 17, 1992

A rotary drill bit comprises a bit body carrying a plurality of preform cutting elements, and a plurality of circumferentially spaced gauge pads which, in use, engage the surrounding formation. Some of the gauge pads carry cutting elements and others are free of cutting elements. To reduce cost, each gauge pad which is free of cutting elements has an outer bearing surface which is more abrasion resistant than the outer surfaces of the gauge pads which carry cutting elements.

US 5186268

“Rotary Drill Bits” February 16, 1993

A rotary drill bit comprises a bit body carrying a plurality of primary preform cutting elements defining a primary cutting profile. The bit includes means to apply a lateral imbalance force to the bit as it rotates, and a portion of the outer periphery of the bit body includes a low friction bearing surface so located as to transmit the lateral force to the formation. There are associated with some of the primary cutting elements respective secondary elements spaced inwardly of the cutting profile defined by the primary cutting elements, but the portion of the periphery of the bit body where the bearing surface is located is substantially free of such secondary elements. The arrangement enhances the anti-whirl characteristics of the bit.

US 5244039

“Rotary Drill Bits” September 14, 1993

A rotary drill bit for drilling holes in subsurface formations comprises a bit body having a shank for connection to a drill string, a plurality of preform primary cutting elements mounted on the bit body and defining a primary cutting profile having a downwardly convex nose portion. There are associated with at least certain of the primary cutting elements respective secondary elements which are spaced inwardly of the primary profile. The distance of the secondary elements from the primary profile, when measured in a direction perpendicular to said profile, is generally greater for secondary elements nearer the nose portion than it is for secondary elements further away from the nose portion, and is preferably such that the vertical distance of the secondary elements from the profile is substantially constant..

US 5553678

“Modulated Bias Units for Rotary Steerable Drilling Systems” September 10, 1996

A modulated bias unit is provided for controlling the direction of drilling of a rotary drill bit when drilling boreholes in subsurface formations. The unit comprises a plurality of hydraulic actuators spaced apart around the periphery of the unit and having movable thrust members hydraulically displaceable outwardly for engagement with the formation of the borehole being drilled. Each actuator has an inlet passage for connection to a source of drilling fluid under pressure and an outlet passage for communication with the annulus. A selector control valve connects the inlet passages in succession to the source of fluid under pressure, as the unit rotates, and a choke is provided to create a pressure drop between the source of fluid under pressure and the selector valve. A further choke is provided in the outlet passage from each actuator unit. The actuators and control valve arrangements may take a number of different forms.

 

US 5671818

“Rotary Drill Bits” September 30, 1997

A rotary drill bit for use in drilling holes in subsurface formations comprises a bit body having a leading face and a gauge region, a number of blades formed on the leading face of the bit and extending outwardly away from the axis of the bit so as to define between the blades a number of fluid channels leading towards the gauge region, a number of cutting elements mounted side-by-side along each blade, and a number of nozzles in the bit body for supplying drilling fluid to the fluid channels for cleaning and cooling the cutting elements. In at least one of the fluid channels, adjacent the gauge region, is an opening into an enclosed passage which passes internally through the bit body to an outlet which, in use, communicates with the annulus between the drill string and the wall of the borehole being drilled. The portion of the gauge region outwardly of the opening comprises a bearing surface which, in use bears against the wall of the bore hole and extends across the width of the channel.

US 5685379

“Method of Operating a Steerable Rotary Drilling System” November 11, 1997

A steerable rotary drilling system comprises a bottom hole assembly which includes, in addition to a drill bit, a modulated bias unit and a control unit including an instrument carrier which is rotatable relative to the bias unit. The bias unit comprises a number of hydraulic actuators spaced apart around the periphery of the unit, each having a movable thrust member which is displaceable outwardly for engagement with the formation. Each actuator can be connected, through a rotatable control valve, to a source of drilling fluid under pressure, the control valve comprising a first part, rotatable with the instrument carrier, which cooperates with a second part which is rotatable with the bias unit. Means are provided to roll stabilize the instrument carrier so that relative rotation between the bias unit and instrument carrier, as the bias unit rotates, causes the valve to operate the actuators in synchronism with rotation of the bias unit so as to apply a lateral bias thereto. In order to neutralize or reduce the net bias applied to the bias unit the instrument carrier may be rotated in various modes instead of being roll stabilized, e.g., it may be rotated at a constant slow speed relative to the bias unit, or at a significantly faster rate so that the actuators do not have time to operate fully. The angular velocity of the carrier may also be varied during its rotation, according to various formulae, in order to vary the net bias. The net bias may also be varied by alternating different modes of carrier rotation.

US 5803185

“Steerable Rotary Drilling Systems and Method of Operating Such Systems” September 8, 1998

A steerable rotary drilling system has a bottom hole assembly which includes, in addition to the drill bit, a modulated bias unit and a control unit, the bias unit comprising a number of hydraulic actuators around the periphery of the unit, each having a movable thrust member which is hydraulically displaceable outwardly for engagement with the formation of the borehole being drilled. Each actuator may be connected, through a control valve, to a source of drilling fluid under pressure and the operation of the valve is controlled by the control unit so as to modulate the fluid pressure supplied to the actuators as the bias unit rotates. If the control valve is operated in synchronism with rotation of the bias unit the thrust members impart a lateral bias to the bias unit, and hence to the drill bit, to control the direction of drilling. Pulses transmitted through the drilling fluid as a result of operation of the bias unit are detected and interpreted at the surface, or at a different location downhole, to obtain information regarding the operation of the bias unit or other parts of the bottom hole assembly. Data signals from downhole sensors may be arranged to modify the control and operation of the bias unit in such manner that the data is encoded as pulses generated in the drilling fluid by the bias unit.

US 5819860

“Rotary Drill Bits” October 13, 1998

A rotary drill bit for use in drilling holes in subsurface formations comprises a bit body having a leading face and a gauge region, a number of blades formed on the leading face of the bit and extending outwardly away from the axis of the bit so as to define between the blades a number of fluid channels leading towards the gauge region, a number of cutting elements mounted side-by-side along each blade, and a number of nozzles in the bit body for supplying drilling fluid to the fluid channels for cleaning and cooling the cutting elements. In at least one of the fluid channels, adjacent the gauge region, is an opening into an enclosed passage which passes internally through the bit body to an outlet which, in use, communicates with the annulus between the drill string and the wall of the borehole being drilled. The portion of the gauge region outwardly of the opening comprises a bearing surface which, in use bears against the wall of the bore hole and extends across the width of the channel.

US 6089332

“Steerable Rotary Drilling Systems” July 18, 2000

A steerable rotary drilling system has a bottom hole assembly which includes, in addition to the drill bit, a modulated bias unit and a control unit, the bias unit comprising a number of hydraulic actuators around the periphery of the unit, each having a movable thrust member which is hydraulically displaceable outwardly for engagement with the formation of the borehole being drilled. Each actuator may be connected, through a control valve, to a source of drilling fluid under pressure and the operation of the valve is controlled by the control unit so as to modulate the fluid pressure supplied to the actuators as the bias unit rotates. If the control valve is operated in synchronism with rotation of the bias unit the thrust members impart a lateral bias to the bias unit, and hence to the drill bit, to control the direction of drilling. Pulses transmitted through the drilling fluid as a result of operation of the bias unit are detected and interpreted at the surface, or at a different location downhole, to obtain information regarding the operation of the bias unit or other parts of the bottom hole assembly. Data signals from downhole sensors may be arranged to modify the control and operation of the bias unit in such manner that the data is encoded as pulses generated in the drilling fluid by the bias unit.

US 6089336

“Rotary Drill Bits” July 18, 2000

A rotary drill bit for use in drilling holes in subsurface formations comprises a bit body having a leading face and a gauge region, a number of blades formed on the leading face of the bit and extending outwardly away from the axis of the bit so as to define between the blades a number of fluid channels leading towards the gauge region, a number of cutting elements mounted side-by-side along each blade, and a number of nozzles in the bit body for supplying drilling fluid to the fluid channels for cleaning and cooling the cutting elements. In each of the fluid channels, adjacent the gauge region, is an opening into an enclosed passage which passes internally through the bit body to an outlet which, in use, communicates with the annulus between the drill string and the wall of the borehole being drilled. The gauge region of the drill bit comprises a substantially continuous bearing surface which extends around the whole of the gauge region.

US 7318492

“Rotary Drill Bit” January 15, 2008

A drill bit for drilling a borehole with a steerable drilling system, the drill bit comprising a longitudinal axis, and a cutting profile with a leading face section blended with a curved region into a tapered gauge region having a tapered gauge profile. The tapered gauge region being tapered with respect to the longitudinal axis determined by the steerable drilling system. The cutting profile and the gauge profile lie wholly within a bit profile envelope made up of a three dimensional surface of two complimentary conical sections set at the tilt angle and separated by and blended with a rounded section which forms an outermost diameter of the bit profile envelope. The rounded section has a diameter substantially equal to a maximum allowable API diameter for the drill bit, and further has a radius of curvature substantially equal to one-half the diameter.

US 10160099

“Selectively Leached, Polycrystalline Structures for Cutting Elements of Drill Bits” December 25, 2018

The rate of leaching of a polycrystalline diamond (PCD) cutting layer for cutting elements or other wear parts is varied by introduction into the PCD of an additive prior to leaching. Selective introduction of the additive into one or more regions of a PCD cutting structure allows controlling leaching rates of selective leaching of parts of the PCD structure, which allows for creating of a boundary between the leached and non-leached regions of a PCD structure to be made so that is not parallel to the surface or surfaces exposed to the leaching solution. The additive is comprised of a material that increases the permeability of the PCD or acceptance of the PCD to the leaching solution, such as a hydrophile.

US 10180032

“Diamond cutting elements for drill bits seeded with HCP crystalline material” January 15, 2019

A polycrystalline diamond compact (PDC), which is attached or bonded to a substrate to form a cutter for a drill bit, is comprised of sintered polycrystalline diamond interspersed with a seed material which has a hexagonal close packed (HCP) crystalline structure. A region of the sintered polycrystalline diamond structure, near one or more of its working surfaces, which has been seeded with an HCP seed material prior to sintering, is leached to remove catalyst. Selectively seeding portions or regions of a sintered polycrystalline diamond structure permits differing leach rates to form leached regions with differing distances or depths and geometries.

US 11156080

“Monitoring System With an Instrumented Surface Top Sub” October 26, 2021

A monitoring and control system that includes an instrumented top sub configured to obtain drilling data.