Abstract: Implementations described herein are directed to a pressure pulse well tool, which may include an upper valve assembly configured to move between a start position and a stop position in a housing. The pressure pulse well tool may also include an activation valve subassembly disposed within the upper valve assembly. The activation valve subassembly may be configured to restrict a fluid flow through the upper valve assembly and increase a fluid pressure across the upper valve assembly. The pressure pulse well tool may further include a lower valve assembly disposed inside the housing and configured to receive the fluid flow from the upper valve assembly. The lower valve assembly may be configured to separate from the upper valve assembly after the upper valve assembly reaches the stop position, causing the fluid flow to pass through the lower valve assembly and to decrease the fluid pressure across the upper valve assembly.

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.

Abstract: Implementations described herein are directed to a pressure pulse well tool, which may include an upper valve assembly configured to move between a start position and a stop position in a housing. The pressure pulse well tool may also include an activation valve subassembly disposed within the upper valve assembly. The activation valve subassembly may be configured to restrict a fluid flow through the upper valve assembly and increase a fluid pressure across the upper valve assembly. The pressure pulse well tool may further include a lower valve assembly disposed inside the housing and configured to receive the fluid flow from the upper valve assembly. The lower valve assembly may be configured to separate from the upper valve assembly after the upper valve assembly reaches the stop position, causing the fluid flow to pass through the lower valve assembly and to decrease the fluid pressure across the upper valve assembly.

Abstract: A cementing swivel includes an outer stationary member having a cement port, an inner rotating member with a bore therethrough, and a torque indicating member coupled to the outer stationary member and configured to provide a visual indication that a predetermined torque load has been reached.

Abstract: A rotary drag bit for drilling a subterranean formation includes a plurality of support elements affixed to the bit body, each forming at least a portion of a cutting element pocket. Each of a plurality of cutting elements has a substantially cylindrical body and is at least partially disposed within a cutter pocket. At least a portion of the substantially cylindrical body of each cutting element is directly secured to at least a portion of a substantially arcuate surface of the bit body. At least a portion of a substantially planar surface of each cutting element matingly engages at least a portion of a substantially planar surface of a support element.

Abstract: A rotary drag bit for drilling a subterranean formation includes a plurality of support elements affixed to the bit body, each forming at least a portion of a cutting element pocket. Each of a plurality of cutting elements has a substantially cylindrical body and is at least partially disposed within a cutter pocket. At least a portion of the substantially cylindrical body of each cutting element is directly secured to at least a portion of a substantially arcuate surface of the bit body. At least a portion of a substantially planar surface of each cutting element matingly engages at least a portion of a substantially planar surface of a support element.

Abstract: A rotary drag bit for drilling a subterranean formation includes a plurality of support elements affixed to the bit body, each forming at least a portion of a cutting element pocket. Each of a plurality of cutting elements has a substantially cylindrical body and is at least partially disposed within a cutter pocket. At least a portion of the substantially cylindrical body of each cutting element is directly secured to at least a portion of a substantially arcuate surface of the bit body. At least a portion of a substantially planar surface of each cutting element matingly engages at least a portion of a substantially planar surface of a support element.

Abstract: A steel body rotary drag bit for drilling a subterranean formation includes a plurality of support elements affixed to the bit body, each forming at least a portion of a cutting element pocket. Each of a plurality of cutting elements has a substantially cylindrical body and is at least partially disposed within a cutter pocket. At least a portion of the substantially cylindrical body of each cutting element is directly secured to at least a portion of a substantially arcuate surface of the bit body. At least a portion of a substantially planar surface of each cutting element matingly engages at least a portion of a substantially planar surface of a support element.

Abstract: A steel body rotary drag bit for drilling a subterranean formation includes a plurality of support elements affixed to the bit body, each forming at least a portion of a cutting element pocket. Each of a plurality of cutting elements has a substantially cylindrical body and is at least partially disposed within a cutter pocket. At least a portion of the substantially cylindrical body of each cutting element is directly secured to at least a portion of a substantially arcuate surface of the bit body. At least a portion of a substantially planar surface of each cutting element matingly engages at least a portion of a substantially planar surface of a support element.

Abstract: Hardfacing is deposited on a PDC-equipped steel body rotary drag bit and forms substantially protruding structural elements, such as wear knots or chip breakers. Hardfacing may also be applied to features such as gage pads, wherein at least two different hardfacing compositions are utilized and specifically located in order to exploit the material characteristics of each type of hardfacing composition employed. The use of multiple hardfacing compositions may further be employed as a wear-resistant coating on various elements of the drill bit. The surfaces to which hardfacing is applied may include machined slots, cavities or grooves providing increased surface area for application of the hardfacing. Additionally, such surface features may serve to effect a desired residual stress state in the resultant hardfacing layer or other structure.

Abstract: 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.

Abstract: 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.