Baker Hughes Corporation

Christopher C Beuershausen

Mark William Dykstra

Michael L Doster

Jack Thomas Oldham

Theodore Edward Zaleski, Jr

Daniel E Ruff

William Heuser

Terry D Watts

Rodney B Walzel

Rudolf C O Pessier

Roland Illerhaus

James A Norris

Michael P Ohanian

Roger W Fincher

John R Spaar

Danny Eugene Scott

Rudolf Carl Pessier

James Leslie Overstreet

Chih C Lin

Don Quy Nguyen

Gregory L Ricks

Terry J Koltermann

Robert James Costo, Jr

Mark E Morris

Ronald L Jones

Rudolf Carl Otto Pessier

Raul E Lema

Chris M McCarty

Steve R Matson

Ronald Hales

Jeffrey B Lund

Lawrence Allen Sinor

Jason Habernal

Juan Miguel Bilen

Thomas Uhlenberg

Larry M Hall

A rotary drilling apparatus and method for drilling subterranean formations, including a body being provided with at least one cutter thereon exhibiting reduced, or limited, exposure to the formation, so as to control the depth-of-cut of the at least one cutter, so as to control the volume of formation material cut per rotation of the drilling apparatus, as well as to control the amount of torque experienced by the drilling apparatus and an optionally associated bottomhole assembly regardless of the effective weight-on-bit are all disclosed. The exterior of the drilling apparatus may include a plurality of blade structures carrying at least one such cutter thereon and including a sufficient amount of bearing surface area to contact the formation so as to generally distribute an additional weight applied to the drilling apparatus against the bottom of the borehole without exceeding the compressive strength of the formation rock.

Drilling apparatus with reduced exposure of cutters and methods of drilling

An earth-boring bit has a bit body that includes head sections, each having depending bit legs with a circumferentially extending outer surface, a leading side, and a trailing side. A bearing shaft depends inwardly from each of the bit legs for mounting a cutter. The bit includes a beveled surface formed at a junction of the leading side and the outer surface of each bit leg. The beveled surface is angled relative to a radial plane emenating from the axis of the bit. The angle of the beveled surface is at least 20 degrees, and extends to an inner surface of the bit leg. The bit can also have a layer of hardfacing on the leading, trailing and shirttail surfaces of the bit leg. A diversion finger of hardfacing extends circumferentially to direct cuttings.

Shirttails for reducing damaging effects of cuttings

A rotary drag bit and method for drilling subterranean formations, including a bit body being provided with at least one cutter thereon exhibiting reduced, or limited, exposure to the formation, so as to control the depth-of-cut of the at least one cutter, so as to control the volume of formation material cut per bit rotation, as well as to control the amount of torque experienced by the bit and an optionally associated bottomhole assembly regardless of the effective weight-on-bit are all disclosed. The exterior of the bit preferably includes a plurality of blade structures carrying at least one such cutter thereon and including a sufficient amount of bearing surface area to contact the formation so as to generally distribute an additional weight applied to the bit against the bottom of the borehole without exceeding the compressive strength of the formation rock.

Drill bits with reduced exposure of cutters

A superabrasive cutter-equipped rotary drag bit especially suitable for directional drilling in subterranean formations is provided. The bit may employ PDC cutters in an engineered cutter placement profile exhibiting optimal aggressiveness in relation to where the cutters are positioned along the profile of the bit extending from a cone region laterally, or radially, outward toward a gage region therefore. The engineered cutter placement profile may include cutters exhibiting differing degrees of aggressiveness positioned in order to maximize rate-of-penetration and minimize torque-on-bit while maintaining side cutting capability and steerability.

Rotary drill bits exhibiting cutting element placement for optimizing bit torque and cutter life

A rotary drag bit and method for drilling subterranean formations including a bit body being provided with at least one cutter thereon exhibiting reduced, or limited, exposure to the formation so as to control the depth-of-cut of the at least one cutter, so as to control the volume of formation material cut per bit rotation, as well as to control the amount of torque experienced by the bit and an optionally associated bottomhole assembly regardless of the effective weight-on-bit. The exterior of the bit preferably includes a plurality of blade structures carrying at least one such cutter thereon and including a sufficient amount of bearing surface area to contact the formation so as to generally distribute an additional weight applied to the bit against the bottom of the borehole without exceeding the compressive strength of the formation rock.

Drill bits with controlled exposure of cutters

Methods of drilling subterranean formations with rotary drag bits equipped with cutting elements including superabrasive, multi-aggressive cutting faces or profiles which are especially suitable for drilling formations of varying hardness and for directional drilling through formations of varying hardness are disclosed. Methods including providing and using rotary drill bits incorporating cutting elements having appropriately aggressive and appropriately positioned cutting surfaces so as to enable the cutting elements to engage the particular formation being drilled at an appropriate depth-of-cut at a given weight-on-bit to maximize rate of penetration without generating excessive, unwanted torque on bit are disclosed. The configuration, surface area, and effective backrake angle of each provided cutting surface, as well as individual cutter backrake angles, may be customized and varied to provide a cutting element having a cutting face aggressiveness profile that varies both longitudinally and radially along the cutting face of the cutting element.

Multi-aggressiveness cuttting face on PDC cutters and method of drilling subterranean formations

A rotary drag bit and method for drilling subterranean formations including a bit body being provided with at least one cutter thereon exhibiting reduced, or limited, exposure to the formation so as to control the depth-of-cut of the at least one cutter, so as to control the volume of formation material cut per bit rotation, as well as to control the amount of torque experienced by the bit and an optionally associated bottomhole assembly regardless of the effective weight-on-bit. The exterior of the bit preferably includes a plurality of blade structures carrying at least one such cutter thereon and including a sufficient amount of bearing surface area to contact the formation so as to generally distribute the weight of the bit against the bottom of the borehole without exceeding the compressive strength of the formation rock.

A PDC-equipped rotary drag bit especially suitable for directional drilling. Cutter chamfer size and backrake angle, as well as cutter backrake, may be varied along the bit profile between the center of the bit and the gage to provide a less aggressive center and more aggressive outer region on the bit face, to enhance stability while maintaining side cutting capability, as well as providing a high rate of penetration under relatively high weight on bit.

Rotary drill bits for directional drilling exhibiting variable weight-on-bit dependent cutting characteristics

A rotary drill bit having a plurality of circumferentially spaced gage pads for drilling bore holes of a preselected trajectory, including lateral or deviated bore holes, in subterranean formations. Each gage pad is provided with, or alternatively associated with, at least one aggressive gage, or side, cutting element having a preselected relative degree of aggressiveness. Selected circumferentially spaced gage pads comprise at least one gage cutting element, or cutting region, disposed thereon and/or comprise alternative gage-cutting elements longitudinally proximate and exclusively associated with a selected gage pad. At least one such gage-cutting element provides more aggressive gage-cutting than at least one other, less aggressive gage-cutting element disposed on, or associated with, a different gage pad. Each of the more aggressive gage pads and each of the less aggressive gage pads may be positioned about the drill bit in a wide variety of circumferential patterns including, but not limited to, an every other alternating gage pad aggressivity pattern. A further optional circumferential gage pad alternation pattern includes, but is not limited to, a first plurality of gage pads having a generally similar first level of aggressiveness being placed proximate and circumferentially adjacent each other on a selected side of the drill bit, with the remaining second plurality of gage pads having a generally similar second level of aggressiveness being placed proximate and circumferentially adjacent each other on the opposite side of the drill bit. Drill bits embodying gage-cutting elements of more than two levels or degrees of aggressivity are also disclosed.

Drill bit with selectively-aggressive gage pads

A rotary drag bit suitable for directional drilling. The bit includes a bit body from which extend radially-oriented blades carrying PDC cutters. The blades extend to primary gage pads, above which secondary gage pads are either longitudinally spaced or rotationally spaced, or both, defining a gap or discontinuity between the primary and secondary gage pads through which drilling fluid from adjacent junk slots may communicate laterally or circumferentially. Longitudinally leading edges of the secondary gage pads carry cutters for smoothing the sidewall of the borehole. The cutters are preferably configured and oriented so as to provide a relatively aggressive cutting edge to the formation in both longitudinal and rotational directions of bit movement, the cutting edges lying adjacent cutting surfaces preferably disposed at negative rake angles to the formation material of the borehole wall for enhanced durability. Cutters may likewise be disposed on the trailing ends of the secondary gage pads to provide an up-drill capability to facilitate removal of the bit from the borehole. The tandem primary and secondary gage pads provide enhanced bit stability and reduced side cutting tendencies. The discontinuities between the primary and secondary gage pads enhance fluid flow from the bit face to the borehole annulus above the bit, promoting formation cuttings removal. The tandem gage arrangement also has utility in conventional bits not designed specifically for directional drilling.

Rotary drill bits for directional drilling employing tandem gage pad arrangement with cutting elements and up-drill capability

A rotary drag bit suitable for directional drilling. The bit includes a bit body from which extend radially-oriented blades carrying PDC cutters. The blades extend to primary gage pads, above which secondary gage pads are either longitudinally spaced or rotationally spaced, or both, defining a gap or discontinuity between the primary and secondary gage pads through which drilling fluid from adjacent junk slots may communicate laterally or circumferentially. Longitudinally leading edges of the secondary gage pads carry cutters, such as chisel-shaped cutters for smoothing the sidewall of the borehole. The cutters are preferably configured and oriented so as to provide a relatively aggressive cutting edge to the formation in both longitudinal and rotational directions of bit movement. Cutters may likewise be disposed on the trailing ends of the secondary gage pads to provide an up-drill capability to facilitate removal of the bit from the borehole.

Growing community of inventors

Spring, TX, United States of America

Christopher C Beuershausen