Grant Prideco, Inc.

A coiled tubing (CT) connector assembly includes a first sub extending between an uphole end and a downhole end, a second sub extending between an uphole end and a downhole end, a slip connected between the first sub and the second sub and comprising one or more engagement members formed on an inner surface thereof for biting into an outer surface of a CT string, a first annular seal and a second annular seal each positioned along an inner surface of at least one of the first sub and the second sub, and a radial port formed in at least one of the first sub and the second sub and located longitudinally between the first annular seal and the second annular seal for pressurizing an internal region of the CT connector assembly extending longitudinally between the first annular seal and the second annular seal.

A gas operated tool for setting a downhole device in a wellbore includes a pressure sub having a first end, a second end, and an inner chamber defining a volume. The inner chamber is configured to receive a power charge. In addition, the tool includes a mandrel operationally attached to the second end of the pressure sub. Further, the tool includes a setting sleeve slidably disposed on the mandrel. The setting sleeve is configured to alternate between a first running position and a second setting position when axial force is applied to the setting sleeve. Still further, the tool includes a dampening assembly coupled to the setting sleeve. The dampening assembly is configured to regulate the axial force applied to the setting sleeve. The dampening assembly includes a housing having an aperture and defining an inner space, dampening material disposed within the inner space, and a plug configured to prevent the dampening material from flowing through the aperture toward the pressure sub, while allowing gas generated by combustion of the power charge to pass through the aperture toward the setting sleeve.

A hybrid rotating sealing element and a hybrid annular sealing system enable the mixed use of a hybrid rotating sealing element and actively controlled non-rotating ACD sealing element within a hybrid ACD-type or other packer-based annular sealing system or the exclusive use of hybrid rotating sealing elements. A seal and bearing housing includes an external sealing feature disposed about an outer portion of the housing, where the external sealing feature prevents leakage through an annular packer when actuated. When actuated the annular packer forms a sealing engagement with the external sealing feature, while permitting an internal mandrel to rotate and form an interference fit with drill pipe, tubulars, or tools disposed therethrough.

A fixed cutter drill bit for drilling an earthen formation comprises a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face includes a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. The drill bit also comprises a cutting structure disposed on the bit face. The cutting structure includes a blade extending radially along the bit face. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, a cutter-supporting surface extending from the leading side to the trailing side. In addition, the drill bit comprises a plurality of cutter element assemblies mounted to the cutter-supporting surface of the blade and arranged in a radially extending row proximal the leading side of the blade. Each cutter element assembly comprises a cutter element carrier and a cutter element fixably attached to the cutter element carrier. The cutter element carrier has a central axis, a leading end relative to the cutting direction of rotation, and a trailing end relative to the cutting direction of rotation. The leading end is defined by a sloped planar surface having a surface vector oriented at an acute angle α relative to the central axis of the cutter element carrier. The cutter element has a central axis, a leading end relative to the cutting direction of rotation, and a trailing end relative to the cutting direction of rotation. The cutter element comprises a substrate extending axially from the trailing end and a cutting layer extending axially from the leading end to the substrate. The cutting layer is fixably attached to the substrate. The substrate comprises a planar surface at the trailing end of the cutter element that is oriented perpendicular to the central axis of the cutter element and the cutting layer comprises a cutting face at the leading end of the cutter element. The planar surface at the trailing end of the cutter element engages and is fixably attached to the sloped planar surface of the cutter element carrier.

The present invention relates to a subsea storage system for storing a water miscible storage fluid and methods related thereto.

A fixed cutter drill bit for drilling a borehole in an earthen formation includes a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face includes a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. In addition, the drill bit includes a cutting structure disposed on the bit face. The cutting structure includes a primary blade extending radially from proximal the bit axis through the cone region and the shoulder region to the gage region. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, and a cutter-supporting surface extending from the leading side to the trailing side. Further, the drill bit includes a plurality of cutter elements mounted to the cutter-supporting surface of the primary blade in the cone region, the shoulder region, and the gage region. Still further, the drill bit includes a gage pad disposed in the gage region and extending axially from the primary blade. The gage pad has a central axis, an uphole end distal the primary blade, a downhole end integral with the primary blade, a leading lateral side relative to the cutting direction of rotation, a trailing lateral side relative to the cutting direction of rotation, and a formation facing surface configured to slidingly engage a sidewall of the borehole during drilling. The formation facing surface of the gage pad extends axially from the uphole end to the downhole end of the gage pad, and wherein the formation facing surface extends laterally from the leading side of the gage pad to the trailing side of the gage pad. The gage pad includes a surface area reducing feature positioned along a middle portion of the gage pad that is axially positioned between and axially spaced from the uphole end of the gage pad and the downhole end of the gage pad. The surface area reducing feature comprises a first recess extending from the formation facing surface toward the bit body.

A damping system for a heave compensator for an off-shore oil rig includes a hydraulic cylinder having a piston and a housing. The hydraulic cylinder is configured for accepting a hydraulic fluid. There is a flow passage for restricting the flow of the hydraulic fluid during movement of the piston in the housing. The hydraulic fluid is a magnetic fluid and the damping system includes a magnetic fluid management system for controlling a magnetic field at the flow passage. A heave compensator including such a damping system, and a method for controlling the damping of a heave compensator are also disclosed, the method including subjecting a magnetic fluid to a magnetic field at a flow passage for restricting the flow of the magnetic fluid.

A fixed cutter drill bit for drilling an earthen formation includes a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face includes a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. The drill bit also includes a cutting structure disposed on the bit face. The cutting structure includes a primary blade extending radially from proximal the bit axis through the cone region and the shoulder region to the gage region. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, and a cutter-supporting surface extending from the leading side to the trailing side. In addition, the drill bit includes a plurality of high-aspect ratio cutter element assemblies mounted to the cutter-supporting surface of the primary blade in the cone region. The cutter element assemblies are arranged in a radially extending row proximal the leading side of the primary blade, wherein each cutter element assembly includes a cutter element carrier and a first cutter element fixably attached to the cutter element carrier. Still further, the drill bit includes a plurality of low-aspect ratio second cutter elements directly mounted to the cutter-supporting surface of the primary blade in the shoulder region or the gage region. The second cutter elements are arranged in a radially extending row proximal the leading side of the primary blade. Each high-aspect ratio cutter element assembly has an exposure H 1 measured perpendicularly from the cutter-supporting surface of the primary blade to a cutting tip of the first cutter element of the cutter element assembly distal the primary blade. Each low-aspect ratio second cutter element has an exposure H 2 measured perpendicularly from the cutter-supporting surface of the primary blade to a cutting tip of the second cutter element distal the primary blade. The exposure H 1 of one or more high-aspect ratio cutter element assemblies in the cone region is greater than the exposure H 2 of one or more low-aspect ratio second cutter elements in the shoulder region or the gage region.

A riserless marine package enables post-BOP utilization of both drill centers simultaneously using an offset riser system to significantly reduce turnaround time between drilling and casing operations and reduce associated costs. A sealing system of the riserless marine package, disposed above the subsea BOP, separates the drilling mud below the sealing system from the seawater above. Drillstrings and casing strings are run through the seawater and transit through the sealing device of the riserless marine package. The rig may assemble and operate a drillstring from the first drilling position and assemble and operate a casing or liner string in the second drilling position. Upon reaching total depth using the offset riser, the rig may trip the drillstring until the BHA clears the subsea BOP. Once the BHA clears the subsea BOP, the rig may then move to insert a casing string hanging from the second drilling position into the well.

A fixed cutter drill bit for drilling an earthen formation includes a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face includes a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. The drill bit also includes a cutting structure disposed on the bit face. The cutting structure includes a primary blade extending radially from proximal the bit axis through the cone region and the shoulder region to the gage region. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, and a cutter-supporting surface extending from the leading side to the trailing side. In addition, the drill bit includes a plurality of cutter elements mounted to the cutter-supporting surface of the primary blade in the cone region, the shoulder region, and the gage region. The cutter elements are arranged in a row proximal the leading side of the primary blade and extending radially from the cone region proximal the bit axis to a gage pad extending from the primary blade. The plurality of cutter elements comprises a plurality of high-aspect ratio cutter elements in the cone region. Each cutter element has an exposure H measured perpendicularly from the cutter-supporting surface of the primary blade to a cutting tip of the cutter element distal the primary blade. The exposure H of one or more of the high-aspect ratio cutter elements in the cone region is greater than the exposure H of one or more cutter elements in the shoulder region and the gage region.