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
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.
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
4.
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 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.
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 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
8.
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.
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 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 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 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
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 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 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 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 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 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 proppant supply system can include a fluid supply system including a blender configured to receive and mix liquid and proppant to form a proppant slurry, and an electrically driven conveyor configured and arranged for direct and metered delivery of proppant to the blender. The proppant supply system can include a proppant source configured to discharge proppant to the conveyor, and a control system for controlling a speed of the conveyor, to control a rate at which proppant is delivered to the blender.
A tubular member includes a central axis, a first end, a second end opposite the first end, and an outer surface extending from the first end to the second end. In addition, the tubular member includes a weld overlay disposed on a portion of the outer surface that is axially spaced from the first end and the second end, wherein the weld overlay comprises a plurality of weld beads.
A friction reduction system includes a housing including a central axis and a central passage, a valve disposed in the housing and including a first valve body and a second valve body wherein the first valve body is permitted to rotate relative to the second valve body, and a mandrel coupled to the second valve body and permitted to travel axially relative to the housing, wherein a first net pressure force is applied against the mandrel that corresponds to a drilling fluid pressure of a drilling fluid in response to flowing the drilling fluid through the valve and transitioning the valve from a closed configuration to an open configuration, and wherein a second net pressure force is applied against the mandrel that corresponds to a wellbore fluid pressure in response to flowing the drilling fluid through the valve and transitioning the valve from the open configuration to the closed configuration.
A pipe handling system for handling drill pipe may include a lifting system configured for handling a load of a pipe stand and a pipe handling robot configured for manipulating a position of the pipe stand. The robot may include an end effector configured for engaging the pipe stand. The system may also include a controller configured for controlling the pipe handling robot to maintain the end effector in substantial alignment with the pipe stand using a vector constraint.
A magnetic linear actuator includes a rotor, a first end cap, a second end cap, a translator, and a guide rod. The rotor includes a first helical array of magnets. The first end cap disposed at a first end of the rotor. The second end cap is disposed at a second end of the rotor. The second end is opposite the first end. The translator is disposed within the rotor, and includes a second helical array of magnets. The guide rod passes through the translator and includes a first end that engages the first end cap, and a second end the engages the second end cap.
A hydraulic fracturing system (100) comprises: a wellhead (146); a pump system (206) that includes one or more high-pressure pumps (238) to deliver fluid to the wellhead (146), and a fluid communication system (208) including a number of valve apparatuses (126) that control the delivery of fluid to the high-pressure pumps (238). The valve apparatuses (126) can receive signals from a control system (150) to regulate the flow rate of the fluid to the high-pressure pumps (238), wherein the control system (150) is configured to: determine a target flow rate for the fluid supplied to the one or more high- pressure pumps (238); determine a valve apparatus actuation scheme based on the target flow rate, the valve apparatus actuation scheme indicating that a valve apparatus (126) of the number of valve apparatuses is to be in an open state; and send an actuation signal to the valve apparatus (126) to actuate a flow control member of the valve apparatus. The corresponding method to control inlet flow to the one or more high-pressure pumps (238) is also disclosed.
F04B 49/22 - Control of, or safety measures for, machines, pumps, or pumping installations, not otherwise provided for in, or of interest apart from, groups by means of valves
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.
E21B 19/09 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods specially adapted for drilling underwater formations from a floating support using heave compensators supporting the drill string
E21B 19/14 - Racks, ramps, troughs or bins, for holding the lengths of rod singly or connected; Handling between storage place and borehole
E21B 19/15 - Racking of rods in horizontal position; Handling between horizontal and vertical position
E21B 19/16 - Connecting or disconnecting pipe couplings or joints
E21B 19/20 - Combined feeding from rack and connecting, e.g. automatically
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.
A screen assembly for vibratory separation includes a screen having a plurality of raised screen components formed therein, with each of the raised screen components defining a face oriented to oppose a flow direction of the screen assembly. In examples, a screen of the screen assembly is assembled from a plurality of metal cloth layers bonded together. Bonding of the metal cloth layers may be accomplished by a sintering process.
A pipe handling system for handling drill pipe on a drill rig may include a lifting system configured for handling a load of a pipe stand and a first pipe handling robot arranged at or near a drill floor of the drill rig and configured for manipulating a bottom end of the pipe stand between a setback area on the drill floor and well center. The system may also include a second pipe handling robot arranged at or near a racking board of the drill rig and configured for manipulating a top end of the pipe stand between the racking board and well center. The first pipe handling robot may have a base that is supported from a location outside a plan view envelope of the setback area of the drill floor.
A pressure pulse system includes a stator, a rotor rotatably positioned in the stator, and a valve assembly configured to induce a pressure pulse in response to rotation of the rotor within the stator, wherein the valve assembly includes a first valve plate coupled to one of the stator and the rotor and including a flow passage, and a second valve plate coupled to the other of the stator or the rotor to which the first valve plate is not coupled and comprising a first flow passage and a second flow passage that is spaced from the first flow passage, wherein the valve assembly provides a first flowpath and a second flowpath between the flow passage of the first valve plate and the second flow passage of the second valve plate.
A magnetic linear actuator includes a stator, a translator, and a ball bearing. The stator includes a first helical array of magnets. The translator is disposed within the stator, and includes a second helical array of magnets. The ball bearing is disposed between the stator and the translator, and includes a plurality of balls in contact with the stator.
A magnetic linear actuator includes a stator and a rotor. The stator includes a first helical array of magnets. The rotor is disposed within the stator and includes a second helical array of magnets. The second helical array of magnets includes a first helical band of magnets and a second helical band of magnets. A first of the magnets of the first helical band coupled to at least one other of the magnets of the first helical band. A first of the magnets of the second helical band coupled to at least one other of the magnets of the second helical band.
A non-contact rotary communication system including an array of light- emitting devices (e.g., LEDs) mounted on a rotary device and a light-sensing device (e.g., photodetector) or array of light-sensing devices mounted, facing the light-emitting devices, on a stationary device, or vice versa, can be used for data transfer between the rotary and stationary devices. In some embodiments, light is emitted in all radial directions with respect to a rotational axis, facilitating continuous data transfer.
G01L 3/12 - Rotary-transmission dynamometers wherein the torque-transmitting element comprises a torsionally-flexible shaft involving electric or magnetic means for indicating involving photoelectric means
G01D 5/26 - Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable using optical means, i.e. using infrared, visible or ultraviolet light
G01M 1/00 - Testing static or dynamic balance of machines or structures
G01N 21/88 - Investigating the presence of flaws, defects or contamination
G01N 21/954 - Inspecting the inner surface of hollow bodies, e.g. bores
An actuator includes housing having a reciprocation axis, motor within the housing, drive gear coupled to the motor, and electromagnetic clutch coupled to the motor and the drive gear. The clutch engages first and second clutch plates responsive to being powered and disengages the clutch plates responsive to not being powered. Actuator includes a ball screw including a nut and a threaded shaft. The nut is coupled to the drive gear and rotation of the drive gear induces rotation of the nut about the reciprocation axis. Rotation of the nut induces motion of the threaded shaft along the reciprocation axis. Actuator includes a fluid damper having a piston coupled to the threaded shaft and disposed within a chamber containing a fluid. Piston includes a port that couples a first chamber portion to a second chamber portion. A brake assembly limits rotation of the nut responsive to the assembly being engaged.
An electronics module or "puck" is positioned in a recess formed in the outer surface of a downhole tool. The puck body includes a flange segment having a first outer diameter, and an adjacent seal-engaging segment having an outer diameter that is less than the outer diameter of the flange segment. An annular seal is disposed about the seal-engaging segment and seals between the puck and the perimeter wall of the recess. A cover ring is disposed over an intermediate segment of the puck body, capturing the seal between the cover and the flange segment. A retainer ring is employed to selectively engage and disengage the perimeter wall of the recess, retaining the puck, seal and covering ring in the recess. A method for installation and removal of the puck is disclosed.
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
E21B 47/14 - 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
G01V 5/10 - Prospecting or detecting by the use of nuclear radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
A close coupled processing system may include a fluid processing system for producing frac fluid for frac operations, a fluid distribution system for distributing the frac fluid to a plurality of pressurization units, and a large bore fluid connection connecting the fluid processing system and the fluid distribution system.
A smart manifold for frac operations may include a support structure and a fluid management system arranged on the support structure. The fluid management system may be configured for receiving low-pressure frac fluid from a fluid processing system, delivering the low-pressure fluid to a plurality of pressurization units, receiving high-pressure fluid from the plurality of pressurization units, and delivering the high-pressure fluid to a well head. The smart manifold may also include a power management system arranged on the support structure. The power management system may be configured for receiving power for frac operations and for delivering power to each of the plurality of pressurization units.
A data acquisition system for monitoring a subsea BOP stack, the BOP stack including a blue control pod and a yellow control pod for operating the BOP stack, the system including an umbilical having a first end and a second end and a reel on a surface vessel. The umbilical is mounted to the reel and extends therefrom. The data acquisition system further including a subsea instrumentation pod mounted to the BOP stack and a first sensor coupled to the instrumentation pod. A lower end of the umbilical is coupled to the instrumentation pod. The instrumentation pod is spaced apart from the blue control pod and the yellow control pod, and the subsea instrumentation pod is electrically isolated and communicatively isolated from the blue control pod and the yellow control pod.
A trailer assembly for carrying coiled tubing includes a main beam assembly extending from a forward end of the trailer assembly to a rear end of the trailer assembly. The main beam assembly includes a forward portion that extends from the forward end of the trailer assembly, a rear portion that extends to the rear end of the trailer assembly, and a middle portion connected between the forward portion and the rear portion and configured to transfer load to the forward portion and the rear portion. The middle portion includes an upper beam section, and a lower beam section vertically separated from the upper beam section. The upper beam section is configured to share a load resultant from a bending force experienced by the lower beam section.
A wellsite monitoring system includes a base station, a plurality of access points, and a wellsite communication interface. The base station is configured to provide communication between the wellsite and a remote system. Each of the access points is configured to communicate with base station, The wellsite communication interface is interfaced to well service equipment, and is configured to communicate with the access points via a wellsite protocol used by the base station, and to present an authentication credential to the base station. The base station is also configured to verify an identity of the wellsite communication interface via the authentication credential, and to enable communication with the wellsite communication interface based on verification of the identity of the wellsite communication interface.
A drill fluid containment device may include a first shell configured for articulating along an axis between a closed position and an open position and a second shell configured for articulating along the axis between a closed position and an open position. In the closed position, the first shell and the second shell may be configured to cooperate with one another to encapsulate a pipe joint of a pipe string. In the open position, the first shell and the second shell may be configured for being spaced apart from the pipe.
A method includes receiving a drill bit design, which specifies design parameters related to a plurality of cutter elements of the drill bit. The method also includes estimating a thermal impact value for the cutter elements based on the design parameters and one or more drilling parameters, and estimating a cooling capacity value for the cutter elements based on the design and one or more cooling parameters. Finally, the method includes presenting the thermal impact values or the cooling capacity values together or individually on a per cutter element basis or as a function of a geometrical or physical property of the cutter elements.
A progressing cavity device includes a stator including a first end, a second end, and an inner surface formed from a metallic material that extends between the first end and the second end, and a rotor rotatably disposed in the stator, the stator including a first end, a second end, and an outer surface formed from a metallic material that extends between the first end and the second end, wherein the outer surface of the rotor contacts the inner surface of the stator, wherein the inner surface of the stator includes a conical taper extending between the first end and the second end, wherein the outer surface of the rotor includes a conical taper extending between the first end and the second end.
F04C 2/107 - Rotary-piston machines or pumps of intermeshing-engagement type, i.e. with engagement of co-operating members similar to that of toothed gearing of internal-axis type with the outer member having more teeth or tooth-equivalents, e.g. rollers, than the inner member with helical teeth
A well system having a well center includes a well platform including a rig floor, a pipe racking system (PRS) supported by the well platform and configured to transport a tubular member between a setback position and a loading position disposed between the setback position and the well center of the well system, and a pipe delivery system (PDS) supported by the well platform and configured to receive the tubular member from the PRS at the loading position and to transport the tubular member from the loading position to the well center.
E21B 19/15 - Racking of rods in horizontal position; Handling between horizontal and vertical position
B25J 11/00 - Manipulators not otherwise provided for
B66C 1/00 - 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
E21B 19/14 - Racks, ramps, troughs or bins, for holding the lengths of rod singly or connected; Handling between storage place and borehole
E21B 19/16 - Connecting or disconnecting pipe couplings or joints
E21B 19/20 - Combined feeding from rack and connecting, e.g. automatically
A valve seat assembly for a pump includes a valve seat housing including a central passage defined by an inner surface and including an insert receptacle, and a valve seat insert that is insertable into the valve seat receptacle and including a contact surface configured to engage a valve of the pump, wherein at least one of the inner surface of the insert receptacle and an outer surface of the valve seat insert is coated with a non-metallic film.
F04B 1/122 - 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 - Details or component parts, e.g. valves, sealings or lubrication means
A dual activity top drive may include a mechanized system configured for suspension from a traveling block of a drill rig and for engaging and rotating a drill string from the top of the drill string. The dual activity top drive may also include a primary pipe handling system suspended from the mechanized system and configured for handling a pipe string and an auxiliary pipe handling system suspended from the mechanized system and configured for handling a segment of pipe to be added or removed from the pipe string.
E21B 19/08 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods
E21B 19/084 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods with flexible drawing means, e.g. cables
E21B 19/16 - Connecting or disconnecting pipe couplings or joints
E21B 19/20 - Combined feeding from rack and connecting, e.g. automatically
48.
WELD JOINTS INVOLVING DISSIMILAR METALS AND METHODS FOR FORMING SAME
A method of joining a steel first member to a stainless steel second member includes buttering a first joint surface on the first member, the buttering including: preheating the first joint surface; welding a border layer of weld material to the first joint surface; and heat treating the border layer and the first joint surface after welding the border layer. A weld is formed between the first and second members after heat treating the border layer and the first joint surface. The border layer and a second joint surface on the second member are preheated; and a body of weld material is added between the border layer and the second joint surface.
Embodiments relate generally to preventing wear to a nominal thickness of a wall of a drill pipe during a downhole operation. A drill pipe may include a first tool joint; a second tool joint; and a tubular section between the first tool joint and the second tool joint, wherein the tubular section comprises a wall with an overall thickness comprising a nominal thickness and a secondary thickness, wherein the secondary thickness is outer to the nominal thickness and is configured to abrade against a wall of the wellbore, thereby reducing the secondary thickness and maintaining the nominal thickness, wherein an ID of each tool joint is less than an ID of the tubular section to accommodate for threaded connectors.
A drill pipe speed sensor includes a roller head assembly including an incremental encoder, a roller to contact a drill pipe, and first and second rotating members. The first rotating member is coupled to the roller, the second rotating member is coupled to the incremental encoder, and the first rotating member is coupled to the second rotating member. The sensor also includes a pivot assembly having mounting plates, pivotal arms, first and second mounting members, and a biasing member. The first and second mounting members extend between the mounting plates, which are parallel to each other. The biasing member contacts the mounting members and extends between the mounting members, and the biasing member is parallel to the mounting plates. The pivotal arms extend from the mounting plates to the roller head assembly and pivot relative to the mounting plates, and the first mounting member is coupled to two pivotal arms.
A well system includes a well platform including a rig floor, a first rig floor robot and a second rig floor robot positioned on the rig floor, wherein the first rig floor robot is configured to guide a lower end of a pipe stand towards a setback position on the rig floor and the second rig floor robot is configured to guide a first pipe joint of the pipe stand into a first mouse hole formed in the rig floor, a mast extending from the rig floor, a racking board coupled to the mast, the racking board configured to secure an upper end of the pipe stand between a pair of finger boards of the racking board, a racking board robot positioned on the racking board and configured to position the upper end of the pipe stand between the pair of finger boards.
B25J 11/00 - Manipulators not otherwise provided for
E21B 19/06 - Elevators, i.e. rod- or tube-gripping devices
E21B 19/084 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods with flexible drawing means, e.g. cables
E21B 19/087 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods by means of a swinging arm
A drilling rig having a lift arm, which may be an auxiliary lift arm provided in addition to a primary lifting cable system of the drilling rig. The lift arm may be configured to hoist and/or manipulate drill collar, drill pipe, or other drilling pipe or conduit. The lift arm may be coupled to a mast of the drilling rig and may have a cantilevered boom extending therefrom. The boom may be configured to pivot between alignment, or near alignment, with well center and a racking board. The lift arm may additionally have a pipe engaging element coupled to the boom. The pipe engaging element may be configured to couple to stands or lengths of drilling pipe. The pipe engaging element may be raised and lowered together with or relative to the boom via a lift line controllable via a hydraulic cylinder, winch, or other suitable mechanism for withdrawing and releasing the line.
A downhole tool includes a housing configured to be connected between two tubular members. The housing includes a chamber and a plug assembly is disposed in the chamber and divides the chamber into an up-hole portion and a downhole portion. The plug assembly includes a glass member having a predetermined residual surface compression, at least a first face, and at least one strength-reducing surface feature on the first face. The strength-reducing surface feature is configured to cause the glass member to disintegrate when the glass member is exposed to a pressure in the up-hole portion of a magnitude that creates a tensile stress on the first face that exceeds the predetermined residual surface compression.
E21B 34/08 - Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 29/00 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
E21B 29/02 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground by explosives or by thermal or chemical means
E21B 29/06 - Cutting windows, e.g. directional window cutters for whipstock operations
E21B 29/08 - Cutting or deforming pipes to control fluid flow
A flaw detection system may include a dedicated monitor volume within a structural component of a system. The monitor volume may establish an air tight space bounded by at least one joint where the joint establishes a portion of a boundary of the air tight space and is in fluid communication with the air tight space. The system may also include a pressure sensing device configured for sensing the pressure in the dedicated monitor volume. A method of monitoring a system for flaw development may include monitoring a pressure sensor configured to sense the pressure in a dedicated monitor volume of a structural component of a system. The method may also include inspecting the structural component to identify a flaw location when the pressure sensor identifies a change in pressure in the dedicated monitor volume.
Techniques related to improving performance of an automated control system for drilling with a drilling system, comprising directing drilling tools on a drilling rig to drill, a borehole using the automated control system, obtaining, from one or more surface sensors disposed at a surface of the drilling site, surface sensor data relating to surface drilling activity of the drilling system, determining, based on a comparison between the surface sensor data and a set of historical data, a set of drilling parameters associated with a drilling state, applying the set of drilling parameters to a physics model of the drilling site to determine a set of downhole parameters for the drilling site, wherein the physics model comprises a simulation of current conditions of the borehole and a drill string of the drilling rig, and adjusting operation of at least one of the drilling tools based on the set of downhole parameters.
A rig control interface includes a plurality of interface systems. Each of the interface systems is configured to manipulate a rig control based on a signal received from an automated rig control system. The interface systems includes a mechanical control interface. The mechanical control interface includes an actuator configured to mechanically move a control handle from a first position to a second position responsive to the signal.
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
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
G01V 11/00 - Prospecting or detecting by methods combining techniques covered by two or more of main groups
A rotary steerable drilling assembly for directional drilling 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 the 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 bend adjustment assembly includes a first position providing a first deflection angle between a longitudinal axis of the driveshaft housing and a longitudinal axis of the bearing mandrel, wherein the bend adjustment assembly includes a second position providing a second deflection angle between the longitudinal axis of the driveshaft housing and the longitudinal axis of the bearing mandrel, the second deflection angle being different from the first deflection angle.
An electric rotating machine includes a housing, a stator, and a rotor. The stator is disposed within the housing. The rotor is disposed within the housing and magnetically coupled to the stator. The rotor includes a plurality of permanent magnets attached to an outer surface of the rotor. The magnets are disposed to form a Halbach array, and the magnets are configured to provide a magnet ratio in a range of 0.7 to 0.9.
B60L 15/00 - Methods, circuits or devices for controlling the propulsion of electrically-propelled vehicles, e.g. their traction-motor speed, to achieve a desired performance; Adaptation of control equipment on electrically-propelled vehicles for remote actuation from a stationary place, from alternative parts of the vehicle or from alternative vehicles of the same vehicle train
B60L 15/20 - Methods, circuits or devices for controlling the propulsion of electrically-propelled vehicles, e.g. their traction-motor speed, to achieve a desired performance; Adaptation of control equipment on electrically-propelled vehicles for remote actuation from a stationary place, from alternative parts of the vehicle or from alternative vehicles of the same vehicle train for control of the vehicle or its driving motor to achieve a desired performance, e.g. speed, torque, programmed variation of speed
A blowout preventer includes a housing including a longitudinal passage and a pair of ram passages extending from the longitudinal passage, a first ram assembly disposed in a first of the pair of ram passages and including first ram block assembly, and a second ram assembly disposed in a second of the pair of ram passages and including a second ram block assembly, wherein the first ram block assembly is configured to include a first configuration in which it sealingly engages an outer surface of a tubular member extending through the longitudinal passage of the housing when the blowout preventer is in a closed position, and a second configuration in which it sealingly engages the second ram block assembly when the blowout preventer is in the closed position.
A lubricator assembly for servicing a tubular member includes a mounting base, a lubricant housing movably coupled to the mounting base and configured to receive lubricant from a lubricant source, a guide pin slidably disposed in the lubricant housing, a first seal positioned between the guide pin and the lubricant housing and a second seal positioned between the guide pin and the lubricant housing, and a first chamber extending between the first seal and the second seal, wherein the guide pin is configured to direct lubricant disposed in the first chamber against the tubular member in response to the tubular member engaging the guide pin.
Pump assemblies, pumping systems including said pump assemblies, and related methods are disclosed. In an embodiment, the pump assembly includes a frame, a fluid end, and a power end coupled to the frame and the fluid end. In addition, the pump assembly includes a plurality of connectors coupled between the fluid end and the frame. Each of the connectors include an axis, a first connector member, and a second connector member. The first connector member is configured to actuate relative to the second connector member to adjust a total axial length of the connector along the axis.
F04B 53/22 - Arrangements for enabling ready assembly or disassembly
F16M 1/00 - Frames or casings of engines, machines, or apparatus; Frames serving as machinery beds
F16M 1/02 - Frames or casings of engines, machines, or apparatus; Frames serving as machinery beds for reciprocating engines or similar machines
F16M 7/00 - FRAMES, CASINGS OR BEDS OF ENGINES, MACHINES OR APPARATUS, NOT SPECIFIC TO ENGINES, MACHINES OR APPARATUS PROVIDED FOR ELSEWHERE; STANDS; SUPPORTS - Details of attaching or adjusting engine beds, frames, or supporting-legs on foundation or base; Attaching non-moving engine parts, e.g. cylinder blocks
F16M 11/04 - Means for attachment of apparatus; Means allowing adjustment of the apparatus relatively to the stand
A mobile proppant delivery system may include a system for unloading proppant transport trailers, storing proppant in silos, and feeding proppant to frac operations. The system may include drive-over conveyors, swiveling distribution heads, internal silo bucket elevators, gravity feed, choke filling, and bases designed with internal conveying systems.
B65G 65/40 - Devices for emptying otherwise than from the top
E21B 43/00 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
B60P 1/36 - Vehicles predominantly for transporting loads and modified to facilitate loading, consolidating the load, or unloading using endless chains or belts thereon
B60P 3/00 - Vehicles adapted to transport, to carry or to comprise special loads or objects
B65D 88/12 - Large containers rigid specially adapted for transport
B65D 88/26 - Hoppers, i.e. containers having funnel-shaped discharge sections
B65G 3/04 - Storing bulk material or loose, i.e. disorderly, articles in bunkers, hoppers or like large containers
63.
PUMP ASSEMBLIES AND PUMPING SYSTEMS INCORPORATING PUMP ASSEMBLIES
A pump assembly (100) includes a power end (109) including an output shaft (118) having an output shaft axis (115). The pump assembly includes a fluid end (60) including a piston (64) configured to reciprocate to pressurize the working fluid. Further, the pump assembly includes a transmission (120) coupled to each of the power end (109) and the fluid end (60). The transmission includes a carriage (150) coupled to the piston and a pivoting arm (144) pivotably coupled to the carriage at a first connection about a first pivot axis (143"). The first pivot axis extends in a perpendicular direction to a direction of the output shaft axis, and rotation of the output shaft about the output shaft axis is configured to cause the pivoting arm to pivot about the first pivot axis at the first connection and to cause the carriage to reciprocate (151).
F04B 23/06 - Combinations of two or more pumps the pumps being all of reciprocating positive-displacement type
F04B 15/02 - Pumps adapted to handle specific fluids, e.g. by selection of specific materials for pumps or pump parts the fluids being viscous or non-homogeneous
F04B 1/14 - 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 having stationary cylinders
F04B 9/02 - Piston machines or pumps characterised by the driving or driven means to or from their working members the means being mechanical
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
A blowout preventer including a housing including a central passage and a first aperture, and a first ram assembly slidably disposed in the first aperture, wherein the first ram assembly includes a ram block and an actuator configured to rotate the ram block when the ram block is disposed in the first aperture of the housing.
A pipe handling system including a lifting system for handling a load of a pipe stand, a pipe handling robot (116a, 116b) configured for engaging with the pipe stand (110) and manipulating a position of the pipe stand (110), and a feedback device configured to provide information about a condition of the pipe stand, the lifting system, or the pipe handling robot (116a, 116b). In some embodiments, the pipe handling robot (116a) may be a first robot configured for engaging with and manipulating a first end of the pipe stand, and the system may include a second pipe handling robot (116b) configured for engaging with and manipulating a second end of the pipe stand (110).
An end effector (400) for a robotic arm, the end effector (400) comprising: two pipe engaging jaws (404), each jaw comprising an inner contour configured for engaging a pipe section, wherein at least one jaw (404) is a fixed jaw; wherein the end effector (400) is configured to restrict radial movement of the pipe section while permitting axial movement.
E21B 19/087 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods by means of a swinging arm
67.
APPARATUS AND METHOD FOR ASSEMBLING POSITIVE DISPLACEMENT DEVICES
A tool for assembling a positive displacement device includes an expandable core including an outer surface including a helical profile, and an expander configured to expand the expandable core radially outwards in response to displacing the expander in a first axial direction relative to the expandable core.
A well cellar assembly, and a method of using same, with the well cellar including a base plate, the base plate having at least two well slot openings therein for receiving a conductor pipe, and at least one vertically extending side wall connected to the base plate with a fluid tight seal. The at least two well slot openings provide alternative locations for the conductor pipe and at least one of the at least two well slot openings is selected for placement of the conductor pipe.
A pipe handling system may include a travelling block (128) configured for raising and lowering a drill string arranged at well center (138) and for travelling along the drill string. The pipe handling system may also include a primary elevator (132) operably coupled to the travelling block (128) and configured for engaging the drill string to cause the drill string to travel with the travelling block (128). The pipe handling system may also include an auxiliary elevator (134) operable to carry a pipe stand during operation of the travelling block (128) along the drill string.
E21B 19/087 - Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods by means of a swinging arm
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
E21B 19/14 - Racks, ramps, troughs or bins, for holding the lengths of rod singly or connected; Handling between storage place and borehole
E21B 19/16 - Connecting or disconnecting pipe couplings or joints
B66C 1/00 - 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
70.
DEVICES, SYSTEMS, AND METHODS FOR TOP DRIVE CLEARING
Systems and methods for clearing a top drive (118) from an operational area of the mast such that operations may be performed along a top drive guide rail (120) without interference from the top drive (118). The guide rail (120) may be arranged within an operational area of a mast and may have a pair of interchangeable rail sections (122, 124), each of which may be configured for arrangement in either an operating configuration, where the rail section may be positioned within the operational area of the mast to form part of the rail, or a parked configuration, where the rail section may be positioned outside of the operational area. Each interchangeable rail section may be pivotable about an axis and may be arranged on a pivotable gate of the mast.
A downhole motor for drilling a borehole includes a stator assembly including a helical-shaped stator, a rotor assembly rotatably disposed in the stator assembly, wherein the rotor assembly includes a helical-shaped rotor, and a sensor package received in the rotor assembly, wherein the sensor package includes a first pressure sensor, a second pressure sensor, and a plurality of accelerometers.
Disclosed herein are landing assemblies for use within a subterranean wellbore. In some embodiments, the landing sub includes central landing assembly disposed within an outer housing such that an annulus is formed therebetween. The central landing assembly includes a first landing surface, a first plurality of ports, and a second plurality of ports. The first plurality of ports is disposed on an axially opposite side of the first landing surface from the second plurality of ports. The central landing assembly is configured to actuate from a first position, in which the second plurality of ports are not in fluid communication with the annulus, to a second position in which the second plurality of ports are in fluid communication with the annulus, upon engagement of a first flowable valve member with the first landing surface.
E21B 33/16 - Methods or devices for cementing, for plugging holes, crevices, or the like for cementing casings into boreholes using plugs for isolating cement charge; Plugs therefor
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
A crane skidding system for orienting one or more relatively high capacity cranes. A crane of the present disclosure may be arranged on one or more rails. In particular, a crane may have one or more skidding feet configured to engage with and skid along the one or more rails. In some embodiments, the rails may be arranged on, or may be part of, an offshore vessel. Rails may include one or more longitudinal rails and one or more lateral rails. The crane may be a shear leg crane having a support frame, which may be or include an A-frame. Each leg of the A-frame may have a skidding foot for skidding on the rail(s). Skidding tractors may be arranged on the rails and may couple to the crane skidding feet to selectively push or pull the crane along the rails to reach a desired position or orientation.
An annular elastomeric packer for a blowout preventer includes a plurality of circumferentially spaced inserts, wherein at least one of the plurality of inserts includes a rib, and a foot pivotally coupled to the rib, and an elastomeric body coupled to the plurality of inserts and including an inner surface, wherein the foot is configured to resist deformation of the elastomeric body in response to the blowout preventer actuating from a first position to a second position.
A plug assembly for plugging a wellbore tubular comprising a central axis and a seal sub (120) including a plurality of axially extending fingers (129) and a tapered outer surface (138). In addition, the plug assembly includes a sealing element (131) coupled to the axially extending fingers (129) of the seal sub (120). Further, the plug assembly includes a slip sub (140) including a tapered inner surface (146), and a plurality of axially extending fingers (142). The fingers of the slip sub (140) each include one or more teeth (152). The seal sub (120) is configured to be at least partially inserted within the slip sub (140) so that the tapered outer surface (138) engages with the tapered inner surface (146), and axial advance of the tapered inner surface (146) within the tapered outer surface (138) is to radially expand the fingers (142) of the slip sub (140) to engage with an inner surface of the tubular.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
Optimizing performance of an automated control system for drilling may include obtaining instructions to deploy a plurality of event-driven drilling activities comprising a drilling process, obtaining default parameters for a first instance of a first activity of the event-driven drilling activities, deploying the first activity of the drilling activities using the default parameters, comprising performing signal analysis on signal data from one or more sensors utilized for the first activity. Optimizing performance of an automated control system for drilling may also include detecting a trigger for a first instance of a second activity using the default parameters, and determining a trigger signature based on the signal analysis when the trigger for the first instance of the second activity is detected, wherein, when a second instance of the first activity is deployed, the trigger signature is utilized to trigger the deployment of a second instance of the second activity.
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 cutting element (101) for a drill bit (112) includes a PCD cutting face (328) having a ridge (332) that extends away from the periphery towards the center of the cutting face, terminating in a curved, central most ridge end (339). The cutting face further includes a surrounding surface (336) consisting of the entire cutting face except for the ridge. The surrounding surface is free of flats and includes two side regions (330a, 330b) and a ramp region (334) therebetween. The surrounding surface (336) is continuously curved along a curved path that extends from the first side region to the ramp region to the other side region. In profile views, the surrounding surface may be linear moving from the top surface of the ridge to the periphery at every location along the curved path.
E21B 10/42 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
E21B 10/46 - Drill bits characterised by wear resisting parts, e.g. diamond inserts
E21B 10/54 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
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
A drilling system includes a drill string, a plurality of sensors, and a computing system. The drill string includes a downhole motor. The sensors are coupled to the drill string. The computing system is coupled to the sensors. The computing system is configured to compute, based on measurements provided by the sensors, a motor stall index, and to determine, by comparing the motor stall index to a motor stall threshold, whether the downhole motor has stalled. The computing system is also configured to, responsive to a determination that the downhole motor has stalled, adjust operation of the drill string to restart the downhole motor.
Cranes and crane systems with high capacity lifting capabilities, as well as versatility and relatively large operational areas. A crane of the present disclosure may have main boom pivotable about a substantially horizontal axis and a luffing assembly configured for luffing the boom about the axis. The main boom may be pivotable in both a forward luffing operation and a reverse or rearward luffing operation. In this way, the main boom may be operable within a range extending up to 180 degrees. Various adjustment mechanisms may be used to shift the main boom from a forward luffing operation to a reverse luffing operation. Additionally, a crane of the present disclosure may have a utility boom rotatable about a substantially vertical axis. The utility boom may allow for added lateral reach of the crane, thus further increasing the operational area of the crane.
A system for handling tubulars on a rig may include a top handling device configured for arrangement on the rig and for handling a top portion of a tubular to and from a setback area. The system may also include a lower handling device configured for arrangement on the rig and for handling a bottom portion of the tubular between well center and a release position. The system may also include a bottom handling device configured for arrangement on the rig and for handling the bottom portion of the tubular between the release position and the setback area.
An iron roughneck is configured to make and break threaded connections between a pair of tubular members. An example of an iron roughneck includes a torque wrench to grip a first tubular member and a spin wrench to engage and rotate a second tubular member. The spin wrench includes a wrench frame, a roller supported by the wrench frame, and a motor configured to rotate the roller. The roller includes a cylindrical roller body with a cylindrical outer surface, a plurality of retention pockets in the roller body with pocket openings in the outer surface of the roller body, and a plurality of inserts, each insert disposed in one of the retention pockets, wherein each insert is moveable relative to the roller body.
Pipelay reel systems and methods for use in laying flexible or rigid pipe (210) or tubing in on and offshore operations. The pipelay reel system has a pipelay reel (202) having a drum (204) arranged between two flanges (206). At least one flange of the reel has a chute (208) configured to receive an adapter (220) coupled to a starting end of the pipe (210) to be spooled on the reel (202). An initiation line (212) coupled to a winch and intersecting the flange chute may be used to position the adapter (220) with respect to a receiving end of the flange chute (208), and the reel may be rotated to pull the adapter down the chute (208) to a latching end of the chute. Moreover, a latch (234) may be used to secure the adapter (220) in the chute (208) such that the pipe (210) may be spooled onto the reel (202).
A running tool configured to install one or more components of a well system includes a mandrel, a first latch including a collet finger that includes an engagement member, a piston slidably disposed about the mandrel, and a second latch pivotally coupled to the mandrel, wherein the first latch is configured to releasably couple with a first component of the well system.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
84.
ROTATING CONTROL DEVICES AND METHODS TO DETECT PRESSURE WITHIN ROTATING MEMBERS
A rotating control device (100) includes a housing (110) with a sensor port (116) extending to a central housing bore, a sensor (120) in the port, and a rotating sleeve assembly (RSA) (125) extending within the central bore. The RSA (125) includes a sleeve (130) configured to rotate relative to the housing (110) and a second bore coaxially aligned with the central bore of the housing, A piston port (152) in the sleeve extends to the second bore, and a piston (200) disposed in the piston port (152) is configured to reciprocate between a first position and a second position in response to a change in pressure of fluid within the second bore. The piston port (152) and the piston (200) are disposed at a location in the rotating sleeve that passes the sensor periodically when the rotating sleeve rotates; the sensor (120) configured to detect the piston (200) when it rotates past the sensor (120) and is in its second position.
A pressure control device (100) for sealing about a tubular string (102) comprises: a flange (206) disposed about a central axis, an annular extension (226) extending from the flange and an annular seal (305) element coupled to the annular extension. The seal member includes a through-passage (266) for receiving the tubular string and an annular recess (268) in which the annular extension (226) is disposed. The annular extension includes a radially-inward facing surface (230) that includes a tapered region (238) that is nonlinear in an axial cross-section for reducing mechanical stresses in the seal member.
An overpressure control apparatus is used to control jets of high-pressure fracking fluid or other stimulation fluid released from a treatment flowline in cases of overpressure. The apparatus includes a collection tank and one or more valves, which can all be mounted on or integrated to a skid. The sizes and weights of the collection tank and the skid may help to keep the apparatus on the ground during an overpressure event. The apparatus can be provided with an offline testing system that allows an operator to close off the communication between the apparatus and the treatment flowline, and instead, pump a clean fluid such as water at high-pressure to test the proper functioning of the valve.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing faces; Packings therefor
A system includes a string disposed in a wellbore, a first valve coupled to the string, the first valve including a sleeve having an engagement profile with a first coded sequence, a second valve coupled to the string, the second valve including a sleeve having an engagement profile with a second coded sequence that differs from the first coded sequence of the first valve, and a first dart flow transportable through the string, the first dart including a collet finger having a first coded sequence configured to restrict the collet finger from matingly engaging the engagement profile of the first valve while permitting the collet finger to engage the engagement profile of the second valve, wherein the first dart actuates the sleeve of the second valve between first and second positions in response to the collet finger of the first dart matingly engaging the engagement profile of the second valve.
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
E21B 34/00 - Valve arrangements for boreholes or wells
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
A reciprocating pump system includes a reciprocating pump including a fluid end configured to receive a suction fluid flow and discharge a discharge fluid flow, and a suction booster assembly coupled to the fluid end, the suction booster assembly including a venturi including a venturi passage, and a jet configured to jet a fluid received from the discharge of the fluid end into the venturi passage, wherein the suction booster assembly is configured such that the jet of the suction booster assembly jetting the fluid into the venturi passage increases the pressure of the suction fluid flow.
A method for optimizing performance of a drilling process by an automated control system for drilling, comprising obtaining a measure of performance for each drilling activity of a set of drilling activities for the drilling process; calculating an activity performance index for each drilling activity by obtaining reference data for each drilling activity, comparing the measures of performance for each drilling activity to the reference data for the particular drilling activity, calculating the activity performance index for each drilling activity based on the comparison; generating a drilling process performance index based on the activity performance indexes; comparing, for each of the drilling activities, a configuration of one or more drilling parameters to a reference configuration of drilling parameters associated with the reference data for the particular drilling activity; and adjusting the configuration of one or more drilling parameters associated with one or more drilling activities based on the comparison.
Tagging bottom utilizing an automated control system and downhole tools may include determining, by a computer processor, that a drill bit has reached a predetermined distance from a bottom of a wellbore, in response to determining that the bit has reached the predetermined depth, transmitting a rate of penetration set point to reduce a lowering speed of the drill bit, directing the drill bit based on the rate of penetration, determining, by the computer processor, that the rate of penetration is stable, in response to the determining that the rate of penetration has stabilized, automatically taring a surface weight on the drill bit and a differential pressure, and in response to determining that the bit is within a predetermined off bottom range, monitoring for a true bottom based on one or more parameter triggers.
E21B 45/00 - Measuring the drilling time or rate of penetration
E21B 7/00 - Special methods or apparatus for drilling
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
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
E21B 44/04 - Automatic control of the tool feed in response to the torque of the drive
91.
DRILLING RIG SOFTWARE SYSTEM CONTROLS RIG EQUIPMENT TO AUTOMATE ROUTINE DRILLING PROCESSES
Automated drilling may include receiving a tool-agnostic request to perform a process, determining one or more activities to complete the process, identifying a controller module associated with a first activity of the one or more activities, and triggering the controller module to initiate the first activity, wherein the controller module identifies and directs one or more drilling tools to initiate the first activity.
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
An active limiting switch includes a comparator (312) and a power switch (212). The comparator is configured to compare a reference voltage (354) with a sense voltage (352). The sense voltage is representative of a proportional approximation to power in a load (108) being driven by a battery (102). The power switch is configured to be, in response to the reference voltage being less than the sense voltage, in an open state. The power switch is also configured to be, in response to the reference voltage being greater than the sense voltage, in a closed state creating a closed circuit between the battery and the load allowing the battery to provide a first amount of power to the load.
H02H 3/38 - Emergency protective circuit arrangements for automatic disconnection directly responsive to an undesired change from normal electric working condition, with or without subsequent reconnection responsive to phase angle between voltage and current
H02H 9/02 - Emergency protective circuit arrangements for limiting excess current or voltage without disconnection responsive to excess current
H02H 9/04 - Emergency protective circuit arrangements for limiting excess current or voltage without disconnection responsive to excess voltage
H02H 9/00 - Emergency protective circuit arrangements for limiting excess current or voltage without disconnection
A sliding sleeve valve for use in a borehole includes an outer housing including a radial housing slot, a sliding sleeve slidably disposed in the outer housing, the sliding sleeve including a radial sleeve slot and configured to have a first position that restricts fluid communication between the sleeve slot and the housing slot and a second position, spaced from the first position, that permits fluid communication between the sleeve slot and the housing slot, an actuator housing coupled to the outer housing, wherein the actuator housing includes an actuator chamber defined by an inner surface, and wherein the actuator chamber is disposed between an inner surface and an outer surface of the actuator housing, and an actuator assembly disposed in the actuator chamber, wherein the actuator assembly is configured to control movement of the sliding sleeve between the first and second positions.
A marine riser assembly (50) includes a first riser (60) having an upper end coupled to a floating offshore structure (20) and a lower end disposed subsea. In addition, the marine riser assembly includes a second riser (70) having an upper end coupled to the floating offshore structure (20) and a lower end disposed subsea. Further, the marine riser assembly includes a riser interface assembly (100) coupled to a subsea blowout preventer (14), the lower end of the first riser, and the lower end of the second riser. The subsea blowout preventer (14) is disposed at an upper end of a subsea wellbore (19). The first riser (60) and the riser interface assembly (100) are configured to provide access to the wellbore (19) through the subsea blowout preventer (14). The second riser (70) and the riser interface (100) are configured to provide access to the wellbore (19) through the subsea blowout preventer (14).
A system for handling pipes on a drilling rig includes an elevator suspended from a stand transfer vehicle, a top drive or other lifting device of a drilling rig. The system also includes a rig-floor pipe lifting machine (10) including a fork (14) sized to engage a tool-joint (110) of a pipe. A navigation system includes a controller that can be programmed to autonomously drive the rig-floor pipe lifting machine.
A sealing apparatus includes a moveable seal holder with a cavity and includes a seal assembly disposed at least partially in the cavity. The seal assembly includes a resilient seal member including a fluid-facing end with a fluid-facing end surface, and the seal assembly includes an actuator plate configured to reciprocate between a first and a second position relative to the protective plate. The first actuator plate includes a fluid-facing end surface and a first camming surface. The seal assembly further includes a first protective plate disposed between the seal member and the first actuator plate. The actuator plate is configured to compress the seal member and to move the fluid-facing end surface of the seal member outward from a resting position when the actuator plate is in the second position.
An anchor for clamping a handling system deadline and controlled by an actuator, such as a hydraulic cylinder or a gearbox coupled to an electric motor. The anchor may generally operate using a pivoting clamping mechanism, wherein the deadline is held between a static clamp plate and a pivoting clamp plate. The pivoting clamp plate may pivot at a pivot point arranged between the two plates. A bolt may be arranged through an opening in each of the clamp plates. A first end of the bolt may extend beyond an outer surface of the pivoting clamp plate and couple to an end block. At a second end, the bolt may extend beyond an outer surface of the static clamp plate and couple to the actuator. As a linear force is applied to the bolt by the actuator, the bolt may pull the pivoting clamp plate toward the static clamp plate.
A sheave assembly (100, 200, 300, 502) for use in a handling system (608) or tensioning system (618), the sheave assembly (100, 200, 300, 502) having one or more sheaves (104, 204, 304, 712) arranged about a shaft (116, 154, 162, 216, 702) and cone (118) sub-assembly. The shaft (116, 154, 162, 216, 702) and cone (118) sub-assembly may include a pair of bearing cones (118, 158, 166, 406, 412, 414) to interface with a plurality of bearing rollers (120) to facilitate rotation of the one or more sheaves (104, 204, 304, 712) about the shaft (116, 154, 162, 216, 702) and cone (118) sub-assembly. The shaft (116, 154, 162, 216, 702) and cone (118) sub-assembly may be configured to be arranged in a fixed rotational position (402, 408) during handling or tensioning operations (404, 410, 504). The shaft (116, 154, 162, 216, 702) and cone (118) subassembly may further be configured to be rotated (512) or repositioned about a central, longitudinal axis of the sub-assembly. The shaft (116, 154, 162, 216, 702) and cone (118) sub-assembly may be configured to rotate independent of the sheave(s) to reposition the pair of cones (118, 158) with respect to applied loading on the sheave assembly (100, 200, 300, 502) from the handling or tensioning operations (404, 410, 504).
A drilling tool includes a pilot bit coupled to an eccentric reamer that has a reaming side and a stabilizing side. A fluid passageway extends between the reamer and the pilot bit, and the tool includes at least one upwardly-directed nozzle in fluid communication with the fluid passageway and positioned on the stabilizing side of the reamer. The reamer may include a plurality of angularly spaced blades on the reaming side that radially extend a first distance, the reamer blades being disposed within a first arcuate segment defined by the two most distant reamer blades. One or more stabilizing blades extend a second distance that is less than the first distance, the stabilization blades being disposed within a second arcuate segment defined by the two most distant reamer blades and that has the angular measure equal to 360 degrees minus the first arcuate segment.
An intermitter valve for controlling the flow rate and/or pressure of a fluid produced from a well drilled into an oil and gas reservoir includes several seals between a seat connected to the valve body and a sleeve connected to a reciprocating stem. An O-ring disposed in an inner groove of the sleeve can be used to intermittently form an elastomer-to-metal seal against the seat. An O-ring disposed in an outer groove of the seat can be used to intermittently form an elastomer-to-metal seal against the sleeve. A surface proximate to the end of the sleeve can be used to intermittently form a metal-to-metal seal against a surface of the seat. The seat and the sleeve can be part of a valve kit for converting a production choke valve into a flow shut-off device.
F16K 17/32 - Excess-flow valves actuated by the difference of pressure between two places in the flow line acting on a servo-mechanism or on a catch-releasing mechanism
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