A connector for coiled tubing may include a main body configured for welding to a free end of the coiled tubing and having an internal stem extending distally therefrom. The stem may include a sleeve potion and the connector may include an alignment sleeve arranged on the sleeve portion of the stem and being free to rotate relative to the stem. The alignment sleeve may have a longitudinally extending groove on an outside surface thereof for receiving a longitudinal weld bead on an inside surface of the coiled tubing.
A connector for coiled tubing may include a main body configured for welding to a free end of the coiled tubing and having an internal stem extending distally therefrom. The stem may include a sleeve portion and the connector may include an alignment sleeve arranged on the sleeve portion of the stem and being free to rotate relative to the stem. The alignment sleeve may have a longitudinally extending groove on an outside surface thereof for receiving a longitudinal weld bead on an inside surface of the coiled tubing.
F16L 33/34 - Arrangements for connecting hoses to rigid members; Rigid hose-connectors, i.e. single members engaging both hoses with bonding obtained by vulcanisation, gluing, melting, or the like
F16L 33/24 - Arrangements for connecting hoses to rigid members; Rigid hose-connectors, i.e. single members engaging both hoses with parts screwed directly on or into the hose
3.
OFFSHORE WIND TURBINE BLADE INSTALLATION, VESSEL OR BARGE, AND COMBINATIONS
Method for installation of a wind turbine blade to a nacelle installed on an offshore wind turbine tower, comprising: gripping a wind turbine blade by a blade gripping device while said blade gripping device is disengaged from a cart and a boom of a blade installer unit; engaging the blade gripping device with a coupling unit of the cart while the blade continues to be gripped by the blade gripping device, wherein the blade is oriented predominantly horizontally; moving the cart with the blade gripping device and the blade along the boom towards the upper end of the boom; rotating the coupling unit with respect to a cart base of the cart to orient the blade predominantly vertically; using the blade installer unit, aligning the blade with the nacelle for mounting of the blade to the nacelle; and mounting the aligned blade to the nacelle.
A rotary steerable drilling assembly includes a driveshaft rotatably disposed in a driveshaft housing, a bend adjustment assembly coupled to the driveshaft housing, a bearing mandrel coupled to the bend adjustment assembly, and a torque control assembly including a rotor configured to couple with a drill string; a stator assembly coupled to a downhole motor; and a torque control actuator assembly configured to control the amount of torque transmitted between the rotor and the stator assembly, wherein the torque control actuator assembly includes a spool valve including a cylinder including a port and a hydraulically actuatable piston slidably disposed in the cylinder.
In some examples, an apparatus for coupling and decoupling a connector head to and from an end of a wired drill pipe held by an elevator includes an actuator configured to move the connector head between a coupled position and a decoupled position. The actuator is configured to move the connector head in parallel with the longitudinal axis of the wired drill pipe before moving it away from said wired drill pipe when decoupling the connector head from the wired drill pipe, and to move the connector head into the longitudinal axis of the wired drill pipe before moving it in parallel with said longitudinal axis when coupling the connector head to the wired drill pipe.
A progressive cavity device includes a stator, a rotor positioned within the stator, a driveshaft, and a joint coupling the driveshaft and the rotor. The joint includes a pivotable member fixably coupled to and engaged with an end of the driveshaft. The pivotable member has a central axis, a first end proximal the driveshaft, a second end distal the driveshaft, and a radially outer surface extending axially from the first end of the pivotable member to the second end of the pivotable member. The joint also includes a first wear pad mounted on the pivotable member. In addition, the joint includes a torque key disposed about the pivotable member and positioned radially adjacent the radially outer surface of the pivotable member. The torque key is rotationally locked to the rotor.
E21B 17/04 - Couplings; Joints between rod and bit, or between rod and rod
E21B 17/046 - Couplings; Joints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
7.
MOTION RESTRICTOR DEVICE AND SYSTEM FOR OFFSHORE LOADING
A motion restrictor device and system for an offshore loading arrangement is described, wherein the motion restrictor device comprises a first portion, at least two second portions protruding from opposite sides of the first portion, and a restrictive surface on the outside of the first portion, wherein the at least two second portions each comprise a protrusion at least partly extending form restriction areas between each respective two second portion and at least parts of the restrictive surface, adapted to restrict horizontal movement of a bridle.
B63B 27/24 - Arrangement of ship-based loading or unloading equipment for cargo or passengers of pipe-lines
B63B 27/34 - Arrangement of ship-based loading or unloading equipment for cargo or passengers for transfer at sea between ships or between ships and off-shore structures using pipe-lines
B67D 9/00 - Apparatus or devices for transferring liquids when loading or unloading ships
A connection between a first tubular member and a second tubular member includes a first tubular end, a second tubular end, a load shoulder member threadable onto the first tubular end, and a nut receivable around the first tubular end and the load shoulder member and threadable onto the second tubular end. The connection also includes a keyway disposed axially between the load shoulder member and the second tubular end, wherein the keyway is also disposed through the load shoulder member and into the first tubular end to receive a key member.
F16L 19/00 - Joints in which sealing surfaces are pressed together by means of a member, e.g. a swivel nut, screwed on, or into, one of the joint parts
E21B 17/042 - Couplings; Joints between rod and bit, or between rod and rod threaded
E21B 17/043 - Couplings; Joints between rod and bit, or between rod and rod threaded with locking means
E21B 17/046 - Couplings; Joints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
F16L 19/025 - Pipe ends provided with collars or flanges, integral with the pipe or not, pressed together by a screwed member the pipe ends having integral collars or flanges
A pipe-dope application system can include an end effector including an applicator configured to retain pipe-dope for application to a drilling component surface, the end effector adapted for connection with a robotic arm configured to perform operations including: applying pipe-dope to the drilling component surface by moving the applicator along the drill pipe surface; and supplying pipe-dope to the applicator by positioning the applicator within a priming station configured to receive the applicator of the end effector.
The invention relates a motion restrictor device and system for an offshore loading arrangement, wherein the motion restrictor device comprises a first portion, and at least two second portions protruding from opposite sides of the first portion, and a restrictive surface on the outside of the first portion, wherein the at least two second portions comprises a protrusion at least partly extending form restriction areas between each respective two second portion and at least parts of the restrictive surface, adapted to restrict horizontal movement of a bridle.
B63B 27/30 - Arrangement of ship-based loading or unloading equipment for cargo or passengers for transfer at sea between ships or between ships and off-shore structures
B63B 27/24 - Arrangement of ship-based loading or unloading equipment for cargo or passengers of pipe-lines
F16L 33/32 - Arrangements for connecting hoses to rigid members; Rigid hose-connectors, i.e. single members engaging both hoses comprising parts outside the hoses only
11.
MODULAR DRILL BITS WITH MECHANICALLY ATTACHED CUTTER ELEMENT ASSEMBLIES
A modular fixed cutter drill bit for drilling an earthen formation has a central axis and a cutting direction of rotation about the central axis. The drill bit includes a bit body configured to rotate about the central axis in the cutting direction of rotation. The bit body includes a bit face. In addition, the drill bit 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, and a cutter-supporting surface extending from the leading side to the traling side. The blade includes a socket extending from the cutter-supporting surface of the blade. Further, the drill bit includes a cutter element assembly mounted to the blade and extending from a cutter-supporting surface of the blade. The cutter element assembly includes a pod seated in the socket and fixably attached to the blade and a cutter element fixably attached to the pod.
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
E21B 10/633 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable with plural detachable cutting elements independently detachable
E21B 10/567 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
E21B 10/627 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable with plural detachable cutting elements
12.
COILED TUBING INJECTOR WITH REACTIVE CHAIN TENSION
A coiled tubing injector including two or more drive chains each carrying a plurality of grippers for engaging coiled tubing within a grip zone defined between the two or more drive chains, a drive system including at least one hydraulic motor connected to a drive line and a return line forming a drive circuit for fluidly powering the at least one hydraulic motor, and a tension system including at least one hydraulic cylinder for tensioning the two or more drive chains. The tension system can include a reactive chain tension circuit for automatically tensioning the two or more drive chains by maintaining a pressure differential between a fluid pressure within the drive line and a fluid pressure within the at least one hydraulic cylinder.
A mooring buoy includes a cylindrical structural shell. The cylindrical structural shell includes fiberglass reinforced plastic (FRP) and has a first open end and an opposite second open end. A plurality of annular stiffeners are bonded to an inside of the cylindrical structural shell. A first endcap is disposed on the first open end of the cylindrical structural shell. The first endcap is configured to substantially cover the first open end. A second endcap is disposed on the second open end of the cylindrical structural shell. The second endcap is configured to substantially cover the second open end. At least one cylindrical attachment mechanism is coupled to an outside of the cylindrical structural shell. The cylindrical attachment mechanism is configured to attach mooring lines to the cylindrical structural shell.
A mooring buoy includes a cylindrical structural shell. The cylindrical structural shell includes fiberglass reinforced plastic (FRP) and has a first open end and an opposite second open end. A plurality of annular stiffeners are bonded to an inside of the cylindrical structural shell. A first endcap is disposed on the first open end of the cylindrical structural shell. The first endcap is configured to substantially cover the first open end. A second endcap is disposed on the second open end of the cylindrical structural shell. The second endcap is configured to substantially cover the second open end. At least one cylindrical attachment mechanism is coupled to an outside of the cylindrical structural shell. The cylindrical attachment mechanism is configured to attach mooring lines to the cylindrical structural shell.
09 - Scientific and electric apparatus and instruments
42 - Scientific, technological and industrial services, research and design
Goods & Services
Monitoring and control systems for oil and gas wellstream processing systems that include natural gas dehydration units with catalyst media, namely, for CO2 and H2 gas streams, for monitoring water content in the gas streams, monitoring water content in the catalyst media, monitoring the health status of valves, electrical heaters, and air coolers, and controlling when the catalyst media is saturated in water to extend the life of the catalyst media, and components therefor, namely, control program software, moisture sensors, electronic valve actuators, conductivity sensors for electrical heaters, and vibration sensors for air coolers Monitoring and control services for oil and gas wellstream processing systems that include natural gas dehydration units with catalyst media, namely, for CO2 and H2 gas streams, for monitoring water content in the gas streams, monitoring water content in the catalyst media, monitoring the health status of valves and valve actuators, electrical heaters, and air coolers of the wellstream processing systems, controlling when the catalyst media is saturated in water to extend the life of the catalyst media, and providing key performance indicators, alerts, and notifications for the wellstream processing systems
A modular well cellar system can include a planar base member defining an aperture sized to receive a conductor pipe; a first end member secured to the base member and configured to support a first lateral wall of the well cellar excavation; a first side member secured to the base member, the first end member, and the second end member, and configured to support a first longitudinal wall of the well cellar excavation; a second side member secured to the planar base member and the first end member and configured to support a second longitudinal wall of the well cellar excavation; and a seal formed between a top surface of the planar base member and each of the first end member, the first side member, and the second side member.
A modular well cellar system can include a planar base member defining an aperture sized to receive a conductor pipe; a first end member secured to the base member and configured to support a first lateral wall of the well cellar excavation; a first side member secured to the base member, the first end member, and the second end member, and configured to support a first longitudinal wall of the well cellar excavation; a second side member secured to the planar base member and the first end member and configured to support a second longitudinal wall of the well cellar excavation; and a seal formed between a top surface of the planar base member and each of the first end member, the first side member, and the second side member.
A rotor bearing system configured to operatively couple a progressing cavity machine to an external device can comprise a housing including an inner surface defining a first bore extending through the housing along a central axis, a first bearing arranged on the inner surface, and a shaft member including an outer surface extending between a proximal portion and a distal portion of the shaft member and a second bearing arranged on the outer surface, the second bearing the second bearing configured to contact the first bearing to limit eccentric motion of the driveshaft of the external device and the rotor head of the progressing cavity machine relative to a stator of the progressing cavity machine during rotation of the rotor head, the shaft member, and the driveshaft.
A rotor bearing system configured to operatively couple a progressing cavity machine to an external device can comprise a housing including an inner surface defining a first bore extending through the housing along a central axis, a first bearing arranged on the inner surface, and a shaft member including an outer surface extending between a proximal portion and a distal portion of the shaft member and a second bearing arranged on the outer surface, the second bearing the second bearing configured to contact the first bearing to limit eccentric motion of the driveshaft of the external device and the rotor head of the progressing cavity machine relative to a stator of the progressing cavity machine during rotation of the rotor head, the shaft member, and the driveshaft.
A Reid vapor pressure control system includes a separator vessel that receives a multiphase flow stream having a gas phase, an oil phase, and a water phase. The Reid vapor pressure control system further includes a gas phase output meter and one or more liquid phase output meters operably connected to a process controller. The process controller is configured to determine an energy input rate used to reduce the Reid vapor pressure of the oil phase based on the operating parameters of the Reid vapor pressure control system during a disturbance test. During operation, the process controller supplies input energy at the energy input rate to the Reid vapor pressure control system.
Managed pressure drilling using wired drill pipe uses real-time data from downhole sensors to improve management of wellbore pressure, provide early detection of unexpected downhole events, augment surface-based automation, and provide visualization of dynamic wellbore conditions. In addition to improving kick detection and simplifying choke control, the rig crew are provided with actionable information that enables them to advance drilling in an optimal manner. In low specification drilling systems that do not implement managed pressure drilling, data from downhole sensors may be provided to a standalone kick detection system to provide early detection of kicks.
E21B 47/18 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
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
B01D 33/03 - Filters with filtering elements which move during the filtering operation with translationally moving filtering elements, e.g. pistons with vibrating filter elements
E21B 21/06 - Arrangements for treating drilling fluids outside the borehole
B07C 5/00 - Sorting according to a characteristic or feature of the articles or material being sorted, e.g. by control effected by devices which detect or measure such characteristic or feature; Sorting by manually actuated devices, e.g. switches
Various embodiments disclosed relate to a reciprocating triplex pump. The present disclosure includes a reciprocating triplex pump with a longer stroke time. Such a pump can include a prime mover with a shaft extending longitudinally; a gear box arranged longitudinally along the shaft, the gear box for actuating the prime mover; and a slider-crank mechanism laterally offset from the gear box. The slider-crank mechanism can include a rotating member assembly, a sliding member assembly, and a connecting rod assembly.
F04B 27/10 - Multi-cylinder pumps specially adapted for elastic fluids and characterised by number or arrangement of cylinders having cylinders coaxial with, or parallel or inclined to, main shaft axis having stationary cylinders
F04B 35/00 - Piston pumps specially adapted for elastic fluids and characterised by the driving means to their working members, or by combination with, or adaptation to, specific driving engines or motors, not otherwise provided for
This disclosure relates to shaker adjustments based on sensor measurements for sensors positioned at different locations about the shaker. This disclosure explains techniques to adjust a shale shaker as would be used to separate particulates (cuttings and other solids) from drilling fluid (commonly referred to as “mud”) during a drilling operation. Empirical models have been formulated to provide for programming a controller to calculate run-time adjustments to the shaker to increase efficiency. The controller may control one or more shakers concurrently. Different techniques and measurement types may be used concurrently to achieve desired shaker inclination and maintain a proper beach location during operation. Sensors include accelerometers, proximity sensors, and other types of data acquisition devices that may be used to detect motion parameters of an operational (e.g., in-use and running) shaker.
Various embodiments disclosed relate to a reciprocating triplex pump. The present disclosure includes a reciprocating triplex pump with a longer stroke time. Such a pump can include a prime mover with a shaft extending longitudinally; a gear box arranged longitudinally along the shaft, the gear box for actuating the prime mover; and a slider-crank mechanism laterally offset from the gear box. The slider-crank mechanism can include a rotating member assembly, a sliding member assembly, and a connecting rod assembly.
F04B 1/0404 - Multi-cylinder machines or pumps characterised by number or arrangement of cylinders having cylinders in star- or fan-arrangement - Details or component parts
F04B 9/02 - Piston machines or pumps characterised by the driving or driven means to or from their working members the means being mechanical
F04B 17/03 - Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by electric motors
F04B 17/05 - Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by internal-combustion engines
F04B 1/12 - Multi-cylinder machines or pumps characterised by number or arrangement of cylinders having cylinder axes coaxial with, or parallel or inclined to, main shaft axis
A pump system may include a drive shaft extending along a longitudinal axis and supplying rotation about the longitudinal axis, a gear system operably coupled to the shaft for changing the orientation of the rotation, and a slider-crank mechanism. The slider crank mechanism may include a rotating member assembly mechanically coupled to and driven by the gear system. The rotating member assembly may include a plurality of rotating members having respective rotational axes offset laterally from one another and generally orthogonal to the longitudinal axis. The slider crank mechanism may also include a sliding member assembly mechanically coupled to the rotating member assembly. The rotating member assembly may be configured to drive reciprocating motion of the sliding member to alternately draw fluid in and discharge fluid. The slider crank mechanism may also include a connecting rod assembly mechanically coupling the rotating member assembly to the sliding member assembly.
F04B 9/02 - Piston machines or pumps characterised by the driving or driven means to or from their working members the means being mechanical
F16H 21/16 - Gearings comprising primarily only links or levers, with or without slides all movement being in, or parallel to, a single plane for interconverting rotary motion and reciprocating motion
F16H 57/038 - Gearboxes for accommodating bevel gears
28.
Downhole friction reduction systems having a flexible agitator
An agitator deployable in a wellbore includes a housing including a central axis and a central passage, a valve including a first valve body having a first contact face and a second valve body permitted to rotate relative to the first valve body and having a second contact face configured to contact the first contact face, a first valve adapter including a first receptacle which receives at least a portion of the first valve body to couple the first valve adapter to the first valve body, and a flexible valve configured to permit the first valve body to flex relative to the first valve adapter whereby an angular misalignment may form between a central axis of the first valve body and a central axis of the first valve adapter.
An agitator deployable in a wellbore includes a housing including a central axis and a central passage, a valve including a first valve body having a first contact face and a second valve body permitted to rotate relative to the first valve body and having a second contact face configured to contact the first contact face, a first valve adapter including a first receptacle which receives at least a portion of the first valve body to couple the first valve adapter to the first valve body, and a flexible valve configured to permit the first valve body to flex relative to the first valve adapter whereby an angular misalignment may form between a central axis of the first valve body and a central axis of the first valve adapter.
09 - Scientific and electric apparatus and instruments
42 - Scientific, technological and industrial services, research and design
Goods & Services
Downloadable software in the nature of a mobile application that uses artificial intelligence for analyzing and training machines to learn and to improve manufacturing efficiency Providing online non-downloadable software that uses artificial intelligence for analyzing and training machines to learn and to improve manufacturing efficiency
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.
E21B 33/038 - Connectors used on well heads, e.g. for connecting blow-out preventer and riser
E21B 33/076 - Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
A tubular member includes a central axis, a first end, a second end opposite the first end, and a throughbore extending axially from the first end to the second end. In addition, the tubular member includes a first connector at the first end and a second connector at the second end. Further, the tubular member includes a tubular region axially positioned between and axially spaced from the first connector and the second connector. The tubular member also includes a first upset axially positioned between the tubular region and the first connector. The first upset has an internal transition within the throughbore that increases an inner diameter of the throughbore when moving axially from the first upset to the tubular region. Moreover, the tubular member includes a first wear pad integrally formed on the tubular region. An outer diameter of the tubular member is greater along the first wear pad than along the tubular region.
A tubular member includes a central axis, a first end, a second end opposite the first end, and a throughbore extending axially from the first end to the second end. In addition, the tubular member includes a first connector at the first end and a second connector at the second end. Further, the tubular member includes a tubular region axially positioned between and axially spaced from the first connector and the second connector. The tubular member also includes a first upset axially positioned between the tubular region and the first connector. The first upset has an internal transition within the throughbore that increases an inner diameter of the throughbore when moving axially from the first upset to the tubular region. Moreover, the tubular member includes a first wear pad integrally formed on the tubular region. An outer diameter of the tubular member is greater along the first wear pad than along the tubular region.
A valve for a displacement pump includes a valve body having an annular strikeface and defining an annular receptacle, and an annular seal received in the receptacle of the valve body, the seal including an annular contact surface, wherein the seal defines a cumulative displacement ratio of (i) at least one of at most 0.20 at a location that is spaced 40% from an inner diameter (ID) of the contact surface of the seal moving towards an outer diameter (OD) of the contact surface, (ii) at most 0.35 at a location that is spaced 55% from the ID of the contact surface moving towards the OD of the contact surface, and (iii) at most 0.45 at a location that is spaced 65% from the ID of the contact surface moving towards the OD of the contact surface.
A cutter element for a fixed cutter drill bit (100) configured to drill a borehole (20) in a subterranean formation (90) includes a base (210) having a central axis, a first end (210a), a second end (210b), and a radially outer cylindrical surface extending axially from the first end to the second end. In addition, the cutter element includes a cutting layer (220) fixably mounted to the first end (210) of the base. The cutting layer includes a stepped cutting face (221) distal the base and a radially outer cylindrical surface extending axially from the cutting face to the radially outer cylindrical surface of the base. The radially outer cylindrical surface of the cutting layer is contiguous with the radially outer cylindrical surface of the base. The stepped cutting face includes a first step (230), a second step (240) axially spaced from the first step, and a riser axially positioned between the first step and the second step. The first step is axially positioned between the riser and the base.
A method of predictive wear state modeling for an actively controlled sealing element includes applying an external energy source to actuate the sealing element to form an interference fit with a pipe member disposed through a lumen of the sealing element, actively controlling the application of the external energy source to maintain the sealing element's interference fit with the pipe member, collecting process control data at predetermined intervals, determining, for each predetermined interval, a raw value of energy absorbed by the sealing element based at least in part on the collected process control data, and providing an indication of the raw value of energy being absorbed by the actively controlled sealing element.
A cutter element for a fixed cutter drill bit configured to drill a borehole in a subterranean formation includes a base having a central axis, a first end, a second end, and a radially outer cylindrical surface extending axially from the first end to the second end. In addition, the cutter element includes a cutting layer fixably mounted to the first end of the base. The cutting layer includes a stepped cutting face distal the base and a radially outer cylindrical surface extending axially from the cutting face to the radially outer cylindrical surface of the base. The radially outer cylindrical surface of the cutting layer is contiguous with the radially outer cylindrical surface of the base. The stepped cutting face includes a first step, a second step axially spaced from the first step, and a riser axially positioned between the first step and the second step. The first step is axially positioned between the riser and the base.
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 shale shaker for separating formation cuttings from a drilling fluid includes a basket and a screen deck positioned within the basket. The screen deck includes a plurality of screens positioned on a plurality of screen supports, such that each screen is positioned on a corresponding one of the plurality of screen supports. Each screen includes a top side, a bottom side opposite the top side, and a mounting bracket positioned along the bottom side. The mounting bracket includes a pair of parallel first support members and a clamping bar coupled to and extending between the pair of first support members. Each screen support includes a pair of parallel second support members and a latch assembly including a hook assembly positioned between the pair of second support members. The hook assembly is configured to engage with the clamping bar to secure the screen to the screen support.
A shale shaker for separating formation cuttings from a drilling fluid includes a basket and a screen deck positioned within the basket. The screen deck includes a plurality of screens positioned on a plurality of screen supports, such that each screen is positioned on a corresponding one of the plurality of screen supports. Each screen includes a top side, a bottom side opposite the top side, and a mounting bracket positioned along the bottom side. The mounting bracket includes a pair of parallel first support members and a clamping bar coupled to and extending between the pair of first support members. Each screen support includes a pair of parallel second support members and a latch assembly including a hook assembly positioned between the pair of second support members. The hook assembly is configured to engage with the clamping bar to secure the screen to the screen support.
E21B 21/06 - Arrangements for treating drilling fluids outside the borehole
B01D 33/03 - Filters with filtering elements which move during the filtering operation with translationally moving filtering elements, e.g. pistons with vibrating filter elements
09 - Scientific and electric apparatus and instruments
42 - Scientific, technological and industrial services, research and design
Goods & Services
Downloadable computer software for use in supply chain logistics for use in the agriculture industry; Downloadable mobile applications for use in supply chain logistics for use in the agriculture industry Providing on-line non-downloadable software using artificial intelligence for analyzing the supply chain for use in the agriculture industry
43.
AUTOMATED SYSTEMS AND METHODS FOR CONTROLLING THE OPERATION OF DOWNHOLE-ADJUSTABLE MOTORS
A method for drilling a wellbore includes providing a mud motor connected to a downhole end of a drillstring, wherein a bend adjustment assembly of the mud motor is provided in a first configuration, pumping a drilling fluid at a drilling flowrate from a supply pump into the drillstring whereby a drill bit coupled to the drillstring is rotated to drill into the earthen formation, receiving by a drilling controller an actuation command instructing the drilling controller to shift the bend adjustment assembly from the first configuration to a second configuration, and operating by the drilling controller at least one of the supply pump to provide an actuation drilling fluid flowrate stored in a storage device of the drilling controller, and a rotary system to provide an actuation drillstring rotational speed stored in the storage device.
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
A method for drilling a wellbore includes providing a mud motor connected to a downhole end of a drillstring, wherein a bend adjustment assembly of the mud motor is provided in a first configuration, pumping a drilling fluid at a drilling flowrate from a supply pump into the drillstring whereby a drill bit coupled to the drillstring is rotated to drill into the earthen formation, receiving by a drilling controller an actuation command instructing the drilling controller to shift the bend adjustment assembly from the first configuration to a second configuration, and operating by the drilling controller at least one of the supply pump to provide an actuation drilling fluid flowrate stored in a storage device of the drilling controller, and a rotary system to provide an actuation drillstring rotational speed stored in the storage device
A valve for use in a wellbore for facilitating a multi-stage stimulation method includes a first sleeve configured to move to open the valve. In addition, the valve includes a second sleeve configured to move to close the valve. The first sleeve and the second sleeve are both movable in a first direction. Movement of the first sleeve a first distance in the first direction opens the valve and subsequent movement of the second sleeve a second distance in the first direction closes the valve. Further, the valve includes a third profile configured to engage a third key of a tool for operating the valve. The third profile is shaped to prevent movement of the tool in a second direction opposite to the first direction when engaged with the third key of the tool.
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
Various embodiments disclosed relate to a configurable drill fluid containment device. The present disclosure includes a device including a central shell configured to at least partially enclose an end of a drill pipe. The central shell can have two halves, each of the halves having flanges that are configured to attaching one or more extension features to the device. The flanges can be configured to attach extension features at an upper end of the device, a lower end of the device, or both.
A pump monitoring system may include a sensor for monitoring a parameter of a pump system. The sensor may include at least one of an ammeter in electrical communication with an electric motor driving a pump and a torque sensor on a drive shaft that drives a pump. The system may also include a controller in data communication with the sensor to receive sensor data. The controller may be configured to assess the performance of the respective pump in one or more ways. At least one of the one or more ways may include reliance on the sensor data from only one sensor to identify valve or seat wear or failure. Alternatively or additionally, at least one of the one or more ways may identify valve or seat wear or failure without reliance on pump output pressure.
G01R 19/00 - Arrangements for measuring currents or voltages or for indicating presence or sign thereof
G01L 3/10 - Rotary-transmission dynamometers wherein the torque-transmitting element comprises a torsionally-flexible shaft involving electric or magnetic means for indicating
Various embodiments disclosed relate to a configurable drill fluid containment device. The present disclosure includes a device including a central shell configured to at least partially enclose an end of a drill pipe. The central shell can have two halves, each of the halves having flanges that are configured to attaching one or more extension features to the device. The flanges can be configured to attach extension features at an upper end of the device, a lower end of the device, or both.
A pump monitoring system may include a sensor for monitoring a parameter of a pump system. The sensor may include at least one of an ammeter in electrical communication with an electric motor driving a pump and a torque sensor on a drive shaft that drives a pump. The system may also include a controller in data communication with the sensor to receive sensor data. The controller may be configured to assess the performance of the respective pump in one or more ways. At least one of the one or more ways may include reliance on the sensor data from only one sensor to identify valve or seat wear or failure. Alternatively or additionally, at least one of the one or more ways may identify valve or seat wear or failure without reliance on pump output pressure.
F04B 49/00 - Control of, or safety measures for, machines, pumps, or pumping installations, not otherwise provided for in, or of interest apart from, groups
E21B 41/00 - Equipment or details not covered by groups
F04B 17/03 - Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by electric motors
F04B 51/00 - Testing machines, pumps, or pumping installations
F16K 25/00 - VALVES; TAPS; COCKS; ACTUATING-FLOATS; DEVICES FOR VENTING OR AERATING - Details relating to contact between valve members and seats
51.
DRILL BIT CUTTER ELEMENTS WITH MULTIPLE SURFACE FINISHES
A cutter element for a fixed cutter drill bit has a central axis and includes a cylindrical substrate and a cutting layer mounted to the substrate. The cutting layer includes a first end engaged with the substrate, a second end opposite the first end, and a radially outer surface extending axially between the first and second ends. In addition, the cutting layer includes a cutting surface positioned at the second end and a cutting tip positioned between the cutting surface and the radially outer surface. Further, the cutting layer includes a first region on the cutting surface having a first surface roughness, and a second region on the cutting surface having a second surface roughness that is higher than the first surface roughness. The second region covers the central axis along the cutting surface, and the first region extends from the second region to the cutting tip.
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
52.
Tools and Methods for Refacing Tubular Ends Forming a Threaded Connection
A refacing tool includes a feed assembly that holds a first set of cutters positioned for refacing the inner shoulder of a pin or box end of a tubular and a second set of cutters positioned for refacing the outer shoulder of the pin or box end. The axial spacing between the first set of cutters and the second set of cutters is fixed and determined by the geometry of the feed assembly. The refacing tool can simultaneously reface the inner shoulder and the outer shoulder, as well as chamfers.
A tower crane for performing a lifting a load includes an extendable tower assembly having a central axis and including a plurality of separate tower sections, a climbing assembly including a climbing frame positioned on the tower assembly and a latching assembly to transport the climbing assembly vertically along the tower assembly, and a boom assembly atop the tower assembly and including a crane floor, a boom supported on the crane floor, a lifting member coupled to the boom, and a slew bearing coupled to the crane floor and configured to permit the crane floor to rotate about a rotational axis, wherein the slew bearing includes a first bearing position and a second bearing position spaced from the first bearing position relative to the central axis of the tower assembly.
The invention concerns a flare gas recovery system comprising a flare gas source suitable for discharging a multi-phase stream including materials in two or more thermodynamic phases such as natural gas (NG), natural gas liquids (NGLs) and/or water, a separator suitable for separating thermodynamic phases of an incoming fluid, an ejector configured to increase the pressure of the multi-phase stream and a membrane system configured to further separate gaseous fluid discharged from the separator. The invention also concerns a method using such a flare gas recovery system.
B01D 53/22 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by diffusion
C10L 3/10 - Working-up natural gas or synthetic natural gas
A downhole motor for directional drilling includes a driveshaft assembly including a driveshaft housing and a driveshaft rotatably disposed within the driveshaft housing, a bearing assembly including a bearing housing and a bearing mandrel rotatably disposed within the bearing housing, wherein the bearing mandrel is configured to couple with a drill bit, a bend adjustment assembly configured to adjust a bend setting of the downhole motor, a lock piston including an unlocked position, and a locked position configured to lock the bend setting of the bend adjustment assembly, one or more hydraulic pumps configured to actuate the lock piston into the unlocked position to unlock the bend adjustment assembly, and an electronics package configured to indicate the bend setting of the bend adjustment assembly.
E21B 47/09 - Locating or determining the position of objects in boreholes or wells; Identifying the free or blocked portions of pipes
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
56.
SYSTEM FOR CONNECTING POWER OR FLUID LINES TO A FLOATING ENERGY CONVERTER DEVICE
The invention relates to a connection system for connecting at least two cables to or from a floating energy converter device. The system comprising at least two cables, a. lower connection structure and an upper connection structure, at least one longitudinal element joining the lower connection structure and the upper connection structure. The at least two cables run through the lower connection structure and each of the cables are connected to the upper connection structure and each comprises a connectable end at the upper connection structure, wherein the system is non-buoyant, and the at least one longitudinal element is a flexible longitudinal element.
F03D 13/25 - Arrangements for mounting or supporting wind motors; Masts or towers for wind motors specially adapted for offshore installation
H02G 1/10 - Methods or apparatus specially adapted for installing, maintaining, repairing, or dismantling electric cables or lines for laying cables, e.g. laying apparatus on vehicle in or under water
H02G 1/06 - Methods or apparatus specially adapted for installing, maintaining, repairing, or dismantling electric cables or lines for laying cables, e.g. laying apparatus on vehicle
H02G 1/00 - Methods or apparatus specially adapted for installing, maintaining, repairing, or dismantling electric cables or lines
H02G 9/12 - Installations of electric cables or lines in or on the ground or water supported on or from floating structures, e.g. in water
H02G 9/00 - Installations of electric cables or lines in or on the ground or water
F03D 9/25 - Wind motors characterised by the driven apparatus the apparatus being an electrical generator
F03D 80/80 - Arrangement of components within nacelles or towers
E02B 17/00 - Artificial islands mounted on piles or like supports, e.g. platforms on raisable legs; Construction methods therefor
A horizontal pipe storing and stand building system may include a pipe rack and a horizontal stand building system arranged adjacent to the pipe rack and configured to receive tubulars from the pipe rack and construct pipe stands in a horizontal orientation. The system may also include a delivery system arranged adjacent the horizontal stand building system and opposite the pipe rack. The delivery system may be configured to receive horizontally arranged pipe stands from the horizontal stand building system and deliver them to a drill rig.
A washpipe assembly for a rotational device includes a gland assembly, a washpipe positioned within the gland assembly, and a seal assembly positioned about the washpipe within the gland assembly. The seal assembly includes a plurality of ring seals, a plurality of annular chambers positioned between the ring seals along the washpipe, and a pressure manifold fluidly coupled to the plurality of annular chambers. The pressure manifold is configured to receive a first fluid pressure and is configured to apply a plurality of pressures to the annular chambers, and the plurality of pressures are each less than the first fluid pressure.
A centrifuge system includes an inlet fluid conduit to receive a flow of raw fluid, an outlet fluid conduit to receive a flow of effluent fluid, an effluent sensor to determine a density of the effluent fluid, a centrifuge including an inlet to receive the raw fluid, an effluent outlet to discharge the effluent fluid, and a solids outlet configured to discharge solids separated from the raw fluid by the centrifuge, a feed pump to pump the raw fluid to the inlet of the centrifuge at a selected flowrate, and a controller to automatically adjust at least one of a speed of the feed pump, a rotational speed of a bowl of the centrifuge about a rotational axis, and a rotational speed of a conveyor of the centrifuge about the rotational axis in response to a change in the density of the effluent fluid as determined by the effluent sensor.
A washpipe assembly for a rotational device includes a gland assembly, a washpipe positioned within the gland assembly, and a seal assembly positioned about the washpipe within the gland assembly. The seal assembly includes a plurality of ring seals, a plurality of annular chambers positioned between the ring seals along the washpipe, and a pressure manifold fluidly coupled to the plurality of annular chambers. The pressure manifold is configured to receive a first fluid pressure and is configured to apply a plurality of pressures to the annular chambers, and the plurality of pressures are each less than the first fluid pressure.
A system for preventing damage to a power cable for electric power transmission to and from and within a floating offshore wind power plant using non-redundant mooring, after failure of a main loadbearing mooring element is described, comprising at least one power cable safety line having the following properties: It is connected to the same two wind turbines as the power cable it is designed to protect. It has an effective length shorter than the power cable it is designed to protect. It has an effective length longer than what is needed to remain largely unstressed when the distance between the floating wind turbines with intact mooring systems is at its maximum. It has a breaking strength being a predetermined fraction of the strength, which the main loadbearing mooring elements are designed for.
B63B 43/00 - Improving safety of vessels, e.g. damage control, not otherwise provided for
F03D 13/25 - Arrangements for mounting or supporting wind motors; Masts or towers for wind motors specially adapted for offshore installation
B63B 35/44 - Floating buildings, stores, drilling platforms, or workshops, e.g. carrying water-oil separating devices
B63B 21/50 - Anchoring arrangements for special vessels, e.g. for floating drilling platforms or dredgers
H02G 9/02 - Installations of electric cables or lines in or on the ground or water laid directly in or on the ground, river-bed or sea-bottom; Coverings therefor, e.g. tile
H01B 7/282 - Preventing penetration of fluid into conductor or cable
There is described the processing seawater in a subsea facility on the seabed in various methods and apparatus. In various examples, the facility is coupled to at least one well, is configured to provide the well with water to be injected into at least one formation of the well, and comprises filter elements arranged in housings, the filter elements being configured for ultrafiltration or microfiltration. In such examples, treated seawater in at least one of the housings is filtered using at least one filter element, producing thereby filtered water, and at least one filter element in at least one other of the filter housings is cleaned by backwashing performed using at least some of the produced filtered water.
A downhole mud motor includes a driveshaft rotatably disposed in a driveshaft housing, a bearing mandrel coupled to the driveshaft, wherein the bend adjustment assembly includes a first configuration that provides a first deflection angle between the driveshaft housing and the bearing mandrel, wherein the bend adjustment assembly includes a second configuration that provides a second deflection angle between the driveshaft housing and the bearing mandrel, and a locking assembly including a locked configuration configured to lock the bend adjustment assembly into one of the first configuration and the second configuration until the downhole mud motor has at least one of reached a predefined depth in the wellbore, and a mud weight has reached a predefined mud weight threshold at a given depth, in response to which the locking assembly is configured to actuate from the locked configuration to an unlocked configuration.
A multidirectional turret loading system for loading/unloading of fluid between an offshore installation and a vessel is provided, comprising a winch for pulling a messenger line, a messenger line guide roller system, and a turret positioned on the bow, on the sides or aft on the vessel with a mainly vertical rotational axis. The turret comprises a turret frame with a hose access opening and a messenger line access opening. The turret further comprises a bearing arrangement for rotation of the turret, a coupling manifold mounted near the hose access opening, a crude line turret swivel mounted in the center of the turret connecting the coupling manifold to a crude line of the vessel and at least one motor for rotating the turret.
B63B 27/30 - Arrangement of ship-based loading or unloading equipment for cargo or passengers for transfer at sea between ships or between ships and off-shore structures
B63B 27/08 - Arrangement of ship-based loading or unloading equipment for cargo or passengers of winches
B63B 79/40 - Monitoring properties or operating parameters of vessels in operation for controlling the operation of vessels, e.g. monitoring their speed, routing or maintenance schedules
66.
MULTI-WINCH HOISTING SYSTEM AND METHOD FOR COMBINING MULTIPLE-WINCHES IN A HOISTING SYSTEM
A hoisting system for hoisting a load includes: i) a main winch system having a main rope with an end connector mounted to an end of the main rope, ii) an auxiliary winch system having an auxiliary rope having at least one rope connector of which at least one is a splitable rope connector, the auxiliary rope comprising a first section and a second section connected to the first section via the splitable rope connector, wherein the splitable rope connector comprises at least two connector parts that are releasably connected with each other for allowing quick disconnection and reconnection between the second section and the first section, wherein the connector parts (are configured for releasably connecting with the end connector of the main rope, and iii) a hang-off point placed and configured for at least temporarily holding a respective rope connector of the auxiliary rope for transferring the load to the hang-off point. The system may include two auxiliary winch systems.
B66C 23/18 - Cranes comprising essentially a beam, boom or triangular structure acting as a cantilever and mounted for translatory or swinging movements in vertical or horizontal planes or a combination of such movements, e.g. jib cranes, derricks or tower cranes specially adapted for use in particular locations or for particular purposes
F16M 13/02 - Other supports for positioning apparatus or articles; Means for steadying hand-held apparatus or articles for supporting on, or attaching to, an object, e.g. tree, gate, window-frame, cycle
B66D 1/26 - Rope, cable, or chain winding mechanisms; Capstans having several drums or barrels
F16G 11/00 - Means for fastening cables or ropes to one another or to other objects; Caps or sleeves for fixing on cables or ropes
67.
Disc Grinding Device and Grinder Comprising the Same
The invention relates to a disc grinding device (2) with a stator disc (3) and a rotor disc (4) which are disposed coaxially with respect to a common disc axis and have at least approximately the same diameter, and the mutually facing sides of which correspondingly contain an annular toothed stator surface and an annular toothed rotor surface, wherein the annular toothed stator surface contains at least one stator ring region with stator teeth, which are spaced apart by stator grooves in the peripheral direction, and the annular toothed rotor surface contains at least one rotor ring region with rotor teeth, which are spaced apart by rotor grooves in the peripheral direction, wherein the toothed rotor surfaces and the toothed stator surfaces define an annular grinding gap and are disposed and formed in such a way that the grinding gap becomes narrower radially in the direction from the disc axis towards the edge of the stator disc (3) and rotor disc (4), wherein the rotor teeth and rotor grooves extend in an inclined or curved manner with respect to the radial direction of the rotor disc (4), and/or wherein at least two stator ring regions with stator teeth and/or rotor ring regions with rotor teeth lie adjacently in the radial direction of the stator disc (3) or rotor disc (4) respectively and have stator teeth or rotor teeth respectively and/or stator grooves or rotor grooves respectively of different designs, and/or wherein the stator grooves and/or rotor grooves become narrower in the direction from the disc axis towards the edge of the stator disc (3) or rotor disc (4) respectively. The invention furthermore relates to a grinder (1) comprising such a disc grinding device (2).
The invention relates to a disc grinding device (2) with a stator disc (3) and a rotor disc (4) which are disposed coaxially with respect to a common disc axis and have at least approximately the same diameter, and the mutually facing sides of which correspondingly contain an annular toothed stator surface and an annular toothed rotor surface, wherein the annular toothed stator surface contains at least one stator ring region with stator teeth, which are spaced apart by stator grooves in the peripheral direction, and the annular toothed rotor surface contains at least one rotor ring region with rotor teeth, which are spaced apart by rotor grooves in the peripheral direction, wherein the toothed rotor surfaces and the toothed stator surfaces define an annular grinding gap and are disposed and formed in such a way that the grinding gap becomes narrower radially in the direction from the disc axis towards the edge of the stator disc (3) and rotor disc (4), wherein the rotor teeth and rotor grooves extend in an inclined or curved manner with respect to the radial direction of the rotor disc (4), and/or wherein at least two stator ring regions with stator teeth and/or rotor ring regions with rotor teeth lie adjacently in the radial direction of the stator disc (3) or rotor disc (4) respectively and have stator teeth or rotor teeth respectively and/or stator grooves or rotor grooves respectively of different designs, and/or wherein the stator grooves and/or rotor grooves become narrower in the direction from the disc axis towards the edge of the stator disc (3) or rotor disc (4) respectively. The invention furthermore relates to a grinder (1) comprising such a disc grinding device (2).
A mounting bracket for a solar array includes a top hat assembly including an outer top hat having a longitudinally extending first rail configured to contact a solar module of the solar array, and an inner top having a longitudinally extending second rail also configured to contact the solar module, an actuator arm assembly comprising a pair of actuator arms which extend from the top hat assembly and which form an opening configured to receive a tubular member of the solar array, and a fastener assembly configured to connect the pair of actuator arms and secure the mounting bracket to both the solar module and the tubular member.
A mounting bracket for a solar array includes a top hat assembly including an outer top hat having a longitudinally extending first rail configured to contact a solar module of the solar array, and an inner top having a longitudinally extending second rail also configured to contact the solar module, an actuator arm assembly comprising a pair of actuator arms which extend from the top hat assembly and which form an opening configured to receive a tubular member of the solar array, and a fastener assembly configured to connect the pair of actuator arms and secure the mounting bracket to both the solar module and the tubular member.
A coiled tubing injector including two or more drive chains each carrying a plurality of grippers for engaging coiled tubing within a grip zone defined between the two or more drive chains, a drive system including at least one hydraulic motor connected to a drive line and a return line forming a drive circuit for fluidly powering the at least one hydraulic motor, and a tension system including at least one hydraulic cylinder for tensioning the two or more drive chains. The tension system can include a reactive chain tension circuit for automatically tensioning the two or more drive chains by maintaining a pressure differential between a fluid pressure within the drive line and a fluid pressure within the at least one hydraulic cylinder.
A passive spacer system may include a racking board comprising a slot and a spacer arranged along the slot such that a portion of the spacer impinges on the slot. The spacer may be biased in a neutral position and configured to move to a spacing position due to motion of tubulars into and out of the racking board, which interact with the portion of the spacer that impinges on the slot.
A passive spacer system may include a racking board comprising a slot and a spacer arranged along the slot such that a portion of the spacer impinges on the slot. The spacer may be biased in a neutral position and configured to move to a spacing position due to motion of tubulars into and out of the racking board, which interact with the portion of the spacer that impinges on the slot.
A passive spacer system may include a racking board comprising a slot and a spacer arranged along the slot such that a portion of the spacer impinges on the slot. The spacer may be biased in a neutral position and configured to move to a spacing position due to motion of tubulars into and out of the racking board, which interact with the portion of the spacer that impinges on the slot.
A particle impact drill bit for a well system includes a central axis, a longitudinal first end, a longitudinal second end opposite the first end, and a feed passage extending into the drill bit from the first end, a pilot section located at the second end, the pilot section including one or more converging nozzles in fluid communication with the feed passage, and a reamer section located between the first end and the second end and including one or more reamer blades extending radially outwards from the central axis of the drill bit, and wherein the reamer section defines a maximum width of the drill bit.
An autonomous along string measurement tool may include a data collection and transmission system having a sensor configured to collect the downhole data, a communication tool configured to transmit the downhole data to the surface, and an operations processor configured for receiving downhole data from the sensor and controlling the communication tool to transmit the downhole data. The system may also include a power bus configured for supplying power to the data collection and transmission system, a power source in selective electrical communication with the power bus, and a power gateway. The power gateway may be configured to control the selective electrical communication between the power source and the power bus based on whether tool conditions are suitable for operation.
E21B 47/024 - Determining slope or direction of devices in the borehole
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
A coupling mechanism for securing a tool to a tool arm may include a housing and an engaging lock. The engaging lock may be arranged within the housing and configured for rotation by the tool arm. Rotation of the engaging lock may drive locking mechanisms partially through the housing to establish a longitudinally secured connection.
An autonomous along string measurement tool may include a data collection and transmission system having a sensor configured to collect the downhole data, a communication tool configured to transmit the downhole data to the surface, and an operations processor configured for receiving downhole data from the sensor and controlling the communication tool to transmit the downhole data. The system may also include a power bus configured for supplying power to the data collection and transmission system, a power source in selective electrical communication with the power bus, and a power gateway. The power gateway may be configured to control the selective electrical communication between the power source and the power bus based on whether tool conditions are suitable for operation.
E21B 47/024 - Determining slope or direction of devices in the borehole
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
A polycrystalline composite tool component and associated methods are disclosed. In one example plurality of diamond particles are coated with a conforming catalyst metal coating and a plurality of graphene particles. Various asymmetric distributions of graphene particles are shown that provide a variety of material properties.
A friction reduction system disposable in a wellbore includes a first valve member including an inner surface which includes a valve seat; and a second valve member rotatable concentrically about a central axis of the first valve member and including a radial port coverable by the valve seat of the outer valve member, wherein the friction reduction system includes an open configuration that provides a maximum flow area through a valve of the friction reduction system including the second valve member and the first valve member, wherein the friction reduction system includes a closed configuration that provides a minimum flow area through the valve which is less than the maximum flow area, and wherein the friction reduction system is configured to generate a pressure pulse in a fluid flowing through the friction reduction system in response to the friction reduction system transitioning from the open configuration to the closed configuration.
A friction reduction system disposable in a wellbore includes a first valve member including an inner surface which includes a valve seat; and a second valve member rotatable concentrically about a central axis of the first valve member and including a radial port coverable by the valve seat of the outer valve member, wherein the friction reduction system includes an open configuration that provides a maximum flow area through a valve of the friction reduction system including the second valve member and the first valve member, wherein the friction reduction system includes a closed configuration that provides a minimum flow area through the valve which is less than the maximum flow area, and wherein the friction reduction system is configured to generate a pressure pulse in a fluid flowing through the friction reduction system in response to the friction reduction system transitioning from the open configuration to the closed configuration.
A friction reduction system disposable in a wellbore includes a first valve member including an inner surface which includes a valve seat; and a second valve member rotatable concentrically about a central axis of the first valve member and including a radial port coverable by the valve seat of the outer valve member, wherein the friction reduction system includes an open configuration that provides a maximum flow area through a valve of the friction reduction system including the second valve member and the first valve member, wherein the friction reduction system includes a closed configuration that provides a minimum flow area through the valve which is less than the maximum flow area, and wherein the friction reduction system is configured to generate a pressure pulse in a fluid flowing through the friction reduction system in response to the friction reduction system transitioning from the open configuration to the closed configuration.
Method for installing a wind turbine blade to a nacelle of an offshore wind turbine, comprising the steps of: providing a vessel or barge with wind turbine blades and a blade installer unit comprising a blade receiving cart; at the offshore wind turbine, bringing a boom of the blade installer unit towards a wind turbine tower of the wind turbine; actuating a tower gripping device unit until the tower gripping device unit engages the tower; inserting a blade into the blade receiving cart, wherein the blade is in approximately horizontal position in the cart; moving the blade receiving cart up towards the upper end of the boom of the blade installer unit; rotating the blade until the blade is in approximately vertical position; moving the blade with respect to the cart until the blade engages the nacelle for coupling to the nacelle.
F03D 13/10 - Assembly of wind motors; Arrangements for erecting wind motors
B66C 1/10 - Load-engaging elements or devices attached to lifting, lowering, or hauling gear of cranes, or adapted for connection therewith for transmitting forces to articles or groups of articles by mechanical means
B66C 23/20 - Cranes comprising essentially a beam, boom or triangular structure acting as a cantilever and mounted for translatory or swinging movements in vertical or horizontal planes or a combination of such movements, e.g. jib cranes, derricks or tower cranes specially adapted for use in particular locations or for particular purposes with supporting couples provided by walls of buildings or like structures
A drilling fluid conditioning system for a well system includes a return conduit configured to receive drilling fluid recirculated from a wellbore of the well system, a drilling fluid pre-chilling system in fluid communication with and downstream from the return conduit, wherein the drilling fluid pre-chilling system includes a cooler configured to transfer heat from the drilling fluid to a heat sink, and a solids control system in fluid communication with and downstream from the drilling fluid pre-chilling system, wherein the solids control system is configured to separate at least some solids from the drilling fluid.
A drilling fluid conditioning system for a well system includes a return conduit configured to receive drilling fluid recirculated from a wellbore of the well system, a drilling fluid pre-chilling system in fluid communication with and downstream from the return conduit, wherein the drilling fluid pre-chilling system includes a cooler configured to transfer heat from the drilling fluid to a heat sink, and a solids control system in fluid communication with and downstream from the drilling fluid pre-chilling system, wherein the solids control system is configured to separate at least some solids from the drilling fluid.
A drilling fluid conditioning system for a well system includes a return conduit configured to receive drilling fluid recirculated from a wellbore of the well system, a drilling fluid pre-chilling system in fluid communication with and downstream from the return conduit, wherein the drilling fluid pre-chilling system includes a cooler configured to transfer heat from the drilling fluid to a heat sink, and a solids control system in fluid communication with and downstream from the drilling fluid pre-chilling system, wherein the solids control system is configured to separate at least some solids from the drilling fluid.
A valve lock for a linear valve system includes a housing including a passage configured to receive a rod of a linearly extendable valve member of the linear valve system, and a collet assembly received in the housing, wherein the collet assembly has a central axis extending parallel the rod of the valve member, a radially inner configuration with respect to the central axis of the collet assembly, and a radially outer configuration relative to the central axis of the collet assembly, wherein the lock includes an unlocked configuration associated with the radially outer configuration of the collet assembly, and a locked configuration associated with the radially inner configuration of the collet assembly and which locks against the rod of the valve member and thereby prevent the rod from travelling in at least one axial direction.
A motion-stabilized crane system includes a crane base extending from a first end to a second end opposite the first end, a crane boom having a first end pivotably coupled to the second end of the crane base and a second end opposite the first end, a hoisting cable, a hook, a motion stabilizer including a hook housing in which at least one of the hoisting cable and the hook is received, a linear actuator configured to rotate the hook housing about a first, a sensor configured to capture as a sensor output associated with the position of at least one of the hook and the hoisting cable in the hook housing, and a stabilizer control module configured to activate the linear actuator to reduce an angle formed between at least one of the hook and the hoisting cable and a vertical axis based on the senor output.
B66C 13/06 - Auxiliary devices for controlling movements of suspended loads, or for preventing cable slack for minimising or preventing longitudinal or transverse swinging of loads
B66C 13/16 - Applications of indicating, registering, or weighing devices
An end effector for gripping and spinning a pipe includes a head portion including a first connection interface for connecting the end effector to a robotic arm. In addition, the end effector includes a pair of jaws rotatably connected to the head portion between an open position and a gripping position. Further, the end effector includes a spinner for spinning a pipe held by the pair of jaws in the gripping position around a spinning axis generally corresponding to a longitudinal centre axis of the pipe. The first connection interface has a normal which is substantially parallel to the spinning axis. There is also disclosed a robot including an end effector as well a robot assembly and a drilling installation including such as robot.
There is disclosed an end effector for gripping and spinning a pipe, the end effector com- prising: - a head portion including a first connection interface for connecting the end effector to a robotic arm, - a pair of jaws rotatably connected to the head portion between an open position and a gripping position; - a spinner for spinning a pipe held by the pair of jaws in the gripping position around a spinning axis generally corresponding to a longitudinal centre axis of the pipe, wherein the first connection interface has a normal which is substantially parallel to the spinning axis. There is also disclosed a robot including an end effector as well a robot assembly and a drilling installation including such as robot.
A magnetic transmission system includes an outer gear ring including an outer plurality of permanent magnets and configured to rotate about a rotational drive axis, an inner gear ring positioned within the outer gear ring and including an inner plurality of permanent magnets magnetically coupled to the outer plurality of permanent magnets, and an eccentric bearing assembly configured to convert orbital motion of the inner gear ring about the rotational drive axis into rotational motion of the eccentric bearing assembly about a bearing rotational axis that is radially offset from the rotational drive axis, and a first drive shaft coupled to the outer gear ring and a second drive shaft coupled to the inner gear ring, wherein the outer gear ring and the inner gear ring are configured to provide a gear ratio between the first drive shaft and the second drive shaft.
H02K 49/10 - Dynamo-electric clutches; Dynamo-electric brakes of the permanent-magnet type
H02K 51/00 - Dynamo-electric gears, i.e. dynamo-electric means for transmitting mechanical power from a driving shaft to a driven shaft and comprising structurally interrelated motor and generator parts
A system includes a wellbore that extends from a surface into a subterranean formation. In addition, the system includes a power generation assembly including a fluid circuit that is in fluid communication with the wellbore wherein the power generation assembly is configured to generate electricity in response to a flow of a working fluid through the fluid circuit. Further, the system includes a bubble pump positioned within the wellbore that is configured to circulate the working fluid between the fluid circuit of the power generation assembly and the wellbore via a thermosiphon effect.
E21B 41/00 - Equipment or details not covered by groups
E21B 43/00 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
F24T 10/13 - Geothermal collectors with circulation of working fluids through underground channels, the working fluids not coming into direct contact with the ground using tube assemblies suitable for insertion into boreholes in the ground, e.g. geothermal probes
A drill bit comprises a bit body having a body face and a plurality of blades each extending from the bit body from a root portion adjacent the body face to a tip portion defining a cutting region, each blade having a leading face and a trailing face. The drill bit further comprises at least one outlet port disposed adjacent the leading face of at least one blade at a location between the root and tip portions of said at least one blade, the at least one outlet port for directing drilling fluid towards the cutting region of the at least one blade.
A drill bit comprises a bit body having a body face and a plurality of blades each extending from the bit body from a root portion adjacent the body face to a tip portion defining a cutting region, each blade having a leading face and a trailing face. The drill bit further comprises at least one outlet port disposed adjacent the leading face of at least one blade at a location between the root and tip portions of said at least one blade, the at least one outlet port for directing drilling fluid towards the cutting region of the at least one blade.
A drill bit for drilling a borehole in an earthen formation has a central axis and a cutting direction of rotation. The bit includes a bit body configured to rotate about the axis in the cutting direction of rotation. The bit body includes a bit face. The bit also includes a blade extending radially along the bit face. In addition, the bit includes a first cutter element mounted to a cutter-supporting surface of the blade and a second cutter element mounted to the cutter-supporting surface of the blade. The first cutter element has a central axis and includes a first forward-facing cutting face including a first cutting tip distal the cutter supporting surface and a first planar surface extending radially from the first cutting tip toward the central axis of the first cutter element. The first planar surface is oriented at a first effective backrake angle measured between the cutter supporting surface and a surface vector of the first planar surface. The second cutter element has a central axis and comprises a second forward-facing cutting face including a second cutting tip distal the cutter supporting surface and a second planar surface extending radially from the second cutting tip toward the central axis of the second cutter element. The second planar surface is oriented at a second effective backrake angle measured between the cutter supporting surface and a surface vector of the second planar surface. The second effective backrake angle is greater than the first effective backrake angle.
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 10/55 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits with preformed cutting elements
E21B 10/567 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
98.
FIXED CUTTER DRILL BITS AND CUTTER ELEMENT ARRANGEMENTS FOR SAME
A drill bit for drilling a borehole in an earthen formation has a central axis and a cutting direction of rotation. The bit includes a bit body configured to rotate about the axis in the cutting direction of rotation. The bit body includes a bit face. The bit also includes a blade extending radially along the bit face. In addition, the bit includes a first cutter element mounted to a cutter-supporting surface of the blade and a second cutter element mounted to the cutter-supporting surface of the blade. The first cutter element has a central axis and includes a first forward-facing cutting face including a first cutting tip distal the cutter supporting surface and a first planar surface extending radially from the first cutting tip toward the central axis of the first cutter element. The first planar surface is oriented at a first effective backrake angle measured between the cutter supporting surface and a surface vector of the first planar surface. The second cutter element has a central axis and comprises a second forward-facing cutting face including a second cutting tip distal the cutter supporting surface and a second planar surface extending radially from the second cutting tip toward the central axis of the second cutter element. The second planar surface is oriented at a second effective backrake angle measured between the cutter supporting surface and a surface vector of the second planar surface. The second effective backrake angle is greater than the first effective backrake angle.
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 10/55 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits with preformed cutting elements
E21B 10/567 - Button-type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
99.
FIXED CUTTER DRILL BITS AND CUTTER ELEMENT ARRANGEMENTS FOR SAME
A drill bit for drilling a borehole in an earthen formation has a central axis and a cutting direction of rotation. The bit includes a bit body configured to rotate about the axis in the cutting direction of rotation. The bit body includes a bit face. The bit also includes a blade extending radially along the bit face. In addition, the bit includes a first cutter element mounted to a cutter-supporting surface of the blade and a second cutter element mounted to the cutter-supporting surface of the blade. The first cutter element has a central axis and includes a first forward-facing cutting face including a first cutting tip distal the cutter supporting surface and a first planar surface extending radially from the first cutting tip toward the central axis of the first cutter element. The first planar surface is oriented at a first effective backrake angle measured between the cutter supporting surface and a surface vector of the first planar surface. The second cutter element has a central axis and comprises a second forward-facing cutting face including a second cutting tip distal the cutter supporting surface and a second planar surface extending radially from the second cutting tip toward the central axis of the second cutter element. The second planar surface is oriented at a second effective backrake angle measured between the cutter supporting surface and a surface vector of the second planar surface. The second effective backrake angle is greater than the first effective backrake angle.
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
42 - Scientific, technological and industrial services, research and design
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