A detonation module for a perforation tool is described herein. The detonation module includes a detonator, a switch circuit disposed in a fluid-sealed housing and electrically coupled to the detonator, a shielding circuit coupled to the switch circuit, an annular electrical contact electrically coupled to the switch circuit, and an annular, electrically conductive, compressive member to form a compressive electrical connection with an end of a perforation unit.
Additives configured to temporarily reduce viscosity in oil-based fluids are provided. The additives may be a reaction product of at least one non-ionic additive and at least one acid anhydride of maleic, succinic and/or glutaric acid. The at least one non-ionic additive may be selected from linear or branched alcohols, alcohol ethoxylates, a combination thereof, and/or a derivative thereof.
A system and method that include receiving an initial on-bottom signal that is indicative of an on-bottom state. The system and method also include receiving data indicative of a block position of the block for an in-slips state and a block position for going to an out-of-slips state of a rig. The system and method additionally include receiving data indicative of slips status of slips of the rig that is indicative of in-slips or out-of-slips. The system and method further include utilizing the data indicative of the slips status and the data indicative of the block position to control a drilling operation.
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 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 drilling system may determine a change in motor torque and/or a pressure drop of a downhole motor based on a flow of a drilling fluid through the downhole motor. The drilling system may determine a change in bit torque of a bit with respect to a change in a weight on bit of the bit. Based at least in part on the change in motor pressure and the change in bit torque of the bit with respect to the change in the weight on bit of the bit, the drilling system may adjust a flow rate of the drilling fluid through the downhole motor to reduce a frequency of motor stalls of the downhole motor.
E21B 44/06 - Automatic control of the tool feed in response to the flow or pressure of the motive fluid of the drive
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 may include acquiring real-time data during rig operations that include rig operations for drilling a borehole in a subsurface geologic region using a drillstring that includes a drill bit, where the drillstring includes stands of drill pipe; based on stand statistics, using at least a portion of the real-time data, calibrating a torque and drag model that models torque and drag of the drillstring in the borehole; based on operation statistics, calling for use of the torque and drag model to make a prediction; and, based at least in part on the prediction, detecting an anomaly.
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 submersible component can include a conductor; and a polymeric material disposed about at least a portion of the conductor where the polymeric material includes at least approximately 50 percent by weight polyether ether ketone (PEEK) and at least 5 percent by weight perfluoroalkoxy alkanes (PFA). A submersible electrical unit can include an electrically conductive winding; and a polymeric composite material disposed about at least a portion of the electrically conductive winding where the polymeric composite material includes polymeric material at at least approximately 40 percent by volume and one or more fillers at at least approximately 10 percent by volume.
H01B 3/30 - Insulators or insulating bodies characterised by the insulating materials; Selection of materials for their insulating or dielectric properties mainly consisting of organic substances waxes
H01B 3/42 - Insulators or insulating bodies characterised by the insulating materials; Selection of materials for their insulating or dielectric properties mainly consisting of organic substances waxes polyacetals
H02K 3/34 - Windings characterised by the shape, form or construction of the insulation between conductors or between conductor and core, e.g. slot insulation
A method can include receiving sample information for reservoir fluid samples and automatically selecting one or more equations of state from a plurality of different equations of state, which can suitably match the reservoir fluid samples and/or other samples. Such a method can also include automatically generating initial conditions based at least in part on sample information where such initial conditions along with one or more selected equations of state can be utilized in simulating physical phenomena using at least a reservoir model to generate simulation results. Such a method can include outputting at least a portion of the simulation results, which may be utilized in one or more processes.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
A method may include displaying, in a graphical user interface (GUI) of a display device, an image generated from a well log, receiving, via the GUI, a selection of a portion of the image, obtaining, for the portion of the image, search metadata, and deriving, from the portion of the image, a search pattern including a constraint on a value of a search parameter. The method may further include performing, using the search pattern, a search within the image to obtain search results including matching portions of the image, marking, in the GUI, locations of the search results within the image, receiving, via the GUI, a selection of a search result, and presenting, in the GUI, the search result.
G06F 3/04842 - Selection of displayed objects or displayed text elements
G06F 16/583 - Retrieval characterised by using metadata, e.g. metadata not derived from the content or metadata generated manually using metadata automatically derived from the content
Electric submersible pump systems, and more particularly, seals for ESPs, are provided. An electric submersible pump includes a plurality of impellers; a plurality of diffusers; at least one sealing ring positioned axially between two consecutive diffusers of the plurality of diffusers; and at least one O-ring positioned axially between the at least one sealing ring and a lower of the two consecutive diffusers.
Embodiments presented provide for high reliability and low cost electronics used in hydrocarbon recovery operations. In embodiments, the low cost electronics are used in subsea applications.
A method can include receiving data files, where the data files include different types of content; training an encoder using the data files to generate a trained encoder; compressing each of the data files using the trained encoder to generate a compressed representation of each of the data files; and processing the compressed representations of the data files to generate groups, where each of the groups represents one of the different types of content, where each of the groups includes members, and where each of the members is associated with a corresponding one of the data files.
A method for wellsite control includes, at a computing device, receiving sensor information from one or more sensors; determining at least one notification option based at least partially on the sensor information; selecting at least one notification option based at least partially on the sensor information; and sending a notification to a notification destination.
H04Q 9/00 - Arrangements in telecontrol or telemetry systems for selectively calling a substation from a main station, in which substation desired apparatus is selected for applying a control signal thereto or for obtaining measured values therefrom
E21B 41/00 - Equipment or details not covered by groups
13.
DEVICES AND SYSTEMS FOR CUTTING ELEMENT ASSEMBLIES
A cutting element assembly includes a cutter support including a cutter bore. A cutting element is in the cutter bore and a resilient element is integral with the cutter support. The resilient element is longitudinally compressible and has a displacement of greater than 0.1 mm and optionally less than 2 mm. Another cutting assembly includes a cutter support coupled to multiple cutting elements. A resilient element of the cutter support is compressible based on a force applied to the cutter support through one or more of the cutting elements. The resilient element can include a slit in the cutter support. A slit may, for instance, extend perpendicular or transverse to an axis of the cutting elements and allow the cutter support to flex and close off or reduce a size of the slit when forces act on one or more of the cutting elements.
An automated system for managing gas in an annulus of a production well at a well site, the automated system including: an electrically-controlled valve fluidly coupled to the annulus of the production well, wherein the valve is located at or near the surface at the well site; at least one well sensor configured to measure operational characteristics of the production well at or near the surface; and a gateway device, located at the well site and operably coupled to the valve and the at least one well sensor, wherein the gateway device is configured to collect first sensor data communicated from the at least one well sensor, and process the first sensor data in autonomous control operations that automatically generate and issue commands that are communicated from the gateway device to the valve to regulate the outflow of accumulated gas from the annulus of the production well over time.
The present disclosure relates to a method. The method includes receiving, via one or more processors, colorimetric data corresponding to a portion or integrality of a surface of a field component. The method also includes determining, via the one or more processors, a color value associated with the surface. Further, the method includes retrieving, via the one or more processors, trend data indicating relationships between a plurality of color values and a plurality of conditions corresponding to the field component. Further still, the method includes determining, via the one or more processors, a condition of the plurality of conditions correspond to the field component based on the trend data and the color value. Even further, the method includes generating, via the one or more processors, a condition output based on the determined condition.
A method can include receiving realizations of a model of a reservoir that includes at least one well where the realizations represent uncertainty in a multidimensional space; selecting a portion of the realizations in a reduced dimensional space to preserve an amount of the uncertainty; optimizing an objective function based at least in part on the selected portion of the realizations; outputting parameter values for the optimized objective function; and generating at least a portion of a field operations plan based at least in part on at least a portion of the parameter values.
Methods and equipment are provided for stimulating recovery of hydrocarbons from a subterranean formation traversed by a wellbore, which employ at least one self-resonating nozzle. Fluid under pressure is supplied to the at least one self-resonating nozzle to create a channel in a surface of the subterranean formation facing the at least one self-resonating nozzle. In embodiments, the equipment can be a downhole tool or completion equipment (such as a liner) that is deployed in the wellbore.
A process mimicking forward modeler with deposition and erosion at each specific geological time step. The 3D derived properties are high resolution depositional environments and rock properties that are used to generate multiscale labelled synthetic data. These synthetic data can range from 1D logs such as grain size, gamma ray, density, and velocity, to 3D synthetic seismic, and are used directly as training data for various AIML applications.
G06F 30/27 - Design optimisation, verification or simulation using machine learning, e.g. artificial intelligence, neural networks, support vector machines [SVM] or training a model
19.
FLUID DENSITY AND VISCOSITY MEASUREMENT TOOL WITH NOISE CANCELLATION
A system including a sensor housing including a channel, and cantilever beam connected to the sensor housing and disposed within the channel. The system also includes an actuator connected to the cantilever beam and configured to cause the cantilever beam to vibrate. A sensor is connected to the cantilever beam and is configured to generate a first signal representing a cantilever beam vibration of the cantilever beam. The system also includes an accelerometer connected to at least one of the sensor and the sensor housing, the accelerometer configured to generate a second signal representing an external vibration of the sensor housing. The external vibration changes the cantilever beam vibration. The system also includes a signal processor configured to receive, as input, the first signal and the second signal and to generate, as output, a filtered signal that reduces an effect of the external vibration on the cantilever beam vibration.
A method includes training a proxy machine learning model to predict an output of a simulation of a physics-based model of a subsurface volume, based on simulation results generated based on the physics-based model and historical data, applying a respective set of uncertainty parameters to the trained proxy machine learning model to generate a solution, returning the generated solution as a solution responsive to determining that a difference between the generated solution and the historical data is less than an error tolerance, and visualizing one or more properties of a subsurface volume using the trained proxy model.
A system includes rotational ball seat (RBS), remote operated, and electrical/hydraulic sections. The RBS section includes a spring, a first internal sleeve, and an upper RBS. The remote operated section includes a lower rotational ball valve (RBV) disposed between second and third internal sleeves, and a setting sleeve operatively connected to the lower RBV. During miming-in-hole, the upper RBS is in a restricted position, and the lower RBV is in an open position. The spring compresses the internal sleeves, which sandwich the upper RBS and the lower RBV, until a shear event occurs. An inner diameter of the system closes to facilitate setting of hydraulic equipment. Thereafter, the shear event releases the spring, thereby pushing the internal sleeves, the upper RBS, and the lower RBV downhole, which rotates the upper RBS and the lower RBV into open positions, thereby opening the inner diameter of the system.
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 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
A technique facilitates stimulation of multiple well zones along a multilayered reservoir. The technique utilizes equipment constructed to enable performance of the stimulation job along the multiple well zones, i.e. two or more well zones, prior to gravel packing the multiple well zones. The equipment enables performance of the stimulation job during a single trip downhole. Subsequent actuation of the equipment further enables a multizone gravel packaging operation during the same trip downhole.
A gyroscope assembly is maintained in a park position during drilling activities. In the park position, a sensitive axis of a gyroscope in the gyroscope assembly is perpendicular or approximately perpendicular to a longitudinal axis of a downhole tool. Maintaining the park position during drilling activities reduces the drift bias caused by overloading the input signal of the gyroscope due to rotation of the downhole tool.
An aqueous composition includes an acid, or an ammonium or salt thereof; a hydrogen fluoride (HF) source; and a fluoride scale inhibitor. Various methods include providing the aqueous composition and performing a treatment operation using the aqueous composition.
C09K 8/528 - Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
E21B 37/06 - Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting the deposition of paraffins or like substances
E21B 43/27 - Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids
A system can include a processor; memory operatively coupled to the processor; and processor-executable instructions stored in the memory to instruct the system to: receive a marker on a well log for a well in a geographic region; and iteratively propagate the marker automatically to a plurality of well logs for other wells in the geographic region.
A method, sensor, and non-transitory computer-readable storage medium are provided for estimating actual amplitudes of a waveform. A machine learning model may be trained for an embedded system of a first three-axes sensor having a limited range to estimate the actual amplitudes of a waveform that saturates the first three-axes sensor in a direction of one of the three axes. The embedded system acquires a second waveform during use of a tool including the first three-axes sensor. The second waveform that occurs after a second waveform producing event is isolated. The embedded system extracts a multi-dimensional feature from the isolated second waveform and estimates, using the machine learning model, the actual amplitudes of the second waveform based on the extracted multi-dimensional feature.
A wellbore is plugged using a bismuth alloy. In one embodiment, the bismuth alloy comprises an alloy of bismuth and tin. In another embodiment, the bismuth alloy comprises an alloy of bismuth and silver. The wellbore can be arranged so that a liquid bismuth alloy sets with an excess pressure of the plug relative to the borehole fluid pressure along a desired seal height distance. Other aspects are described and claimed.
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
C09K 8/42 - Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
C09K 8/46 - Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
E21B 29/12 - 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 specially adapted for underwater installations
A ranging workflow to interpret the ultradeep harmonic anisotropic attenuation (UHAA) measurements and estimate the distance and orientation of the existing cased well from the well being drilled is presented herein. The ranging workflow applies to scenarios in which the wells are near parallel to each other and performs reasonably well in boreholes which are more or less perpendicular to the formation layers. The ranging workflow generally includes deploying a deep directional resistivity (DDR) tool into a new wellbore; collecting UHAA data via the DDR tool; determining resistivity values based at least in part on the UHAA data; and determining a distance of the DDR tool from a casing of an existing wellbore proximate the new wellbore based at least in part on the resistivity values and a UHAA response table for the DDR tool.
G01V 3/20 - Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination or deviation specially adapted for well-logging operating with propagation of electric current
E21B 47/024 - Determining slope or direction of devices in the borehole
E21B 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
29.
INTEGRATED AUTONOMOUS OPERATIONS FOR INJECTION-PRODUCTION ANALYSIS AND PARAMETER SELECTION
An integrated autonomous operation system that holistically renders the operation in digital form at multiple scales, including reservoir, surface infrastructure, workflows, processes, and the real asset. The system provides an end-to-end digital twin connecting subsurface to production. A subsurface model identifies and monitors water-producing zones for strategic decisions. The models use intelligent AI to provide optimum water injection setpoints. The models provide data to systems that automatically control the chokes and valves to meet the setpoints, thus achieving fully integrated, autonomous operations.
A fluid system component can include a body that includes a multidimensional shape defined in orthogonal directions and layers stacked along one of the orthogonal directions, where at least one of the layers includes polymeric material and graphene nanoplatelets formed in situ from the polymeric material, and where the graphene nanoplatelets increase stiffness of the polymeric material.
B23K 26/00 - Working by laser beam, e.g. welding, cutting or boring
B29C 64/188 - Processes of additive manufacturing involving additional operations performed on the added layers, e.g. smoothing, grinding or thickness control
C08J 5/00 - Manufacture of articles or shaped materials containing macromolecular substances
C08K 7/00 - Use of ingredients characterised by shape
C08L 101/12 - Compositions of unspecified macromolecular compounds characterised by physical features, e.g. anisotropy, viscosity or electrical conductivity
A method can include receiving seismic survey data of a subsurface environment from a seismic survey utilizing water bed receivers, where each of the receivers includes a clock; assessing one or more clock calibration criteria; based on the assessing, selecting a clock drift processor for processing at least a portion of the seismic survey data from a plurality of different clock drift processors; using at least the clock drift processor, performing a simultaneous inversion for values of model-based parameters; and, using at least a portion of the values, generating processed seismic survey data that represents one or more geological interfaces in the subsurface environment.
Aspects provide for methods that successfully evaluates multiple compressional and shear arrival events received by a sonic logging tool to evaluate the presence of structures, such as shoulder beds, in downhole environments. In particular, the methods described herein enable automated determination of properties of laminated reservoir formations by, for example, enabling the automated determination of arrival times and slownesses of multiple compressional and shear arrival events received by a sonic logging tool.
A method can include generating equipment specifications for a facility project at a field site by simulating physical phenomena using one or more computational simulators; using the equipment specifications and a computational facility planner system, generating a work breakdown structure for the facility project, where the work breakdown structure represents activities to be performed to deliver a defined scope of the facility project within a defined time; rendering a graphical user interface to a display that includes graphical controls for dependencies of the activities and equipment characterized by the equipment specifications; responsive to input received via one or more of the graphical controls, automatically updating at least durations of the activities; and, based at least in part on the updating, generating an optimal scenario for the facility project.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
G06Q 10/0631 - Resource planning, allocation, distributing or scheduling for enterprises or organisations
G06Q 10/067 - Enterprise or organisation modelling
A backup ring for a frac plug. The backup ring may include a plurality of segments defined by a plurality of slots, where each segment is defined by a sequential pair of the plurality of slots. The backup ring may also include a plurality of buttons, wherein at least one button is disposed on each segment. The backup ring creates a backup anchor for the sealing element and reduces or prevents extrusion of the sealing element.
A method can include, responsive to receipt of input characterizing a geologic environment, utilizing a trained machine learning model to identify a number of geologic environments that include corresponding data stored in at least one database; analyzing one or more of the number of geologic environments; and outputting a result based at least in part on the analyzing.
A technique facilitates operation of a slip assembly, e.g. a frac plug assembly, having a plurality of slips. The plurality of slips may selectively be forced in a radially outward direction via, for example, a cone so as to set the slips against a surrounding casing or other tubing. The slip assembly further comprises a mechanism which allows different amounts of radial movement of individuals slips to ensure sufficient setting of the individual slips when the surrounding tubing is oval or otherwise out of round.
An insert assembly for a rotating control device (RCD) includes a seal element configured to form an annular seal about a tubular as the tubular rotates, moves axially, or both. The insert assembly also includes a support member positioned within the seal element, wherein the support member includes a shape memory alloy.
A perforation tool for use in a well bore is described herein. The perforation tool comprises a housing; a plurality of frames that fit inside the housing, each frame having a cylindrical shape with a central axis and a plurality of liners, each liner having an axis perpendicular to the central axis, wherein the axes of the liners of each frame are disposed in a plane perpendicular to the central axis, and the frames are axially stackable; an electrical conductor disposed along a central passage of each frame; a plurality of shaped charges secured in the liners of the frames; a bulkhead member disposed in the housing and forming a seal with the housing; and an initiator module disposed in the housing with the bulkhead member between the initiator module and the plurality of frames.
Systems, computer-readable media, and methods are provided. Relevant documents related to a specific entity are identified based on document metadata. Text and associated spatial coordinates are extracted based on relevant document pages. Significant document entities and associated spatial locations are identified. Page ranking is based on the extracted text and the spatial coordinates, the significant document entities, and image vector representations of the pages. A deep learning language model that utilizes the text and the spatial coordinates, layout information of the document entities, and the image vector representations of the pages is used to extract the user-defined attributes from the relevant document pages. First attribute values associated with the user-defined attributes are aggregated from the pages of one of the relevant documents into a single record. Second attribute values associated with the user-defined attributes are aggregated across the relevant documents. Aggregated records, including a first and second attribute, are written to a database.
A method can include receiving real-time data for a field operation at a wellsite; predicting a future drilling-related loss event based on at least a portion of the real-time data using a trained recurrent neural network model; and, responsive to the predicting, issuing a signal to equipment at the wellsite.
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 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
G06N 3/0442 - Recurrent networks, e.g. Hopfield networks characterised by memory or gating, e.g. long short-term memory [LSTM] or gated recurrent units [GRU]
41.
DEVICES, SYSTEMS, AND METHODS FOR DOWNHOLE POWER GENERATION
A downhole energy harvesting system includes a housing subjected to periodic oscillations. An energy harvesting device is on, in, or otherwise connected to the housing and positioned to generate electricity based on the periodic oscillations. The energy harvesting device is coupled to at least one of a powered component or an energy storage device in order to use or store the harvested energy.
E21B 41/00 - Equipment or details not covered by groups
H02N 2/18 - Electric machines in general using piezoelectric effect, electrostriction or magnetostriction producing electrical output from mechanical input, e.g. generators
A global fluid identity repository is used to maintain and manage fluid characterization data for various fluids utilized in the oil & gas industry, e.g., reservoir fluids within subsurface formations. Tracking and notification services may be utilized to track changes made to a global fluid identity, e.g., changes in fluid sample and/or experiment data for a fluid, and automatically generate notifications when downstream data such as fluid models and/or simulation results become stale as a result of these changes.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
Methods of fracturing a subterranean formation include introducing a fracturing fluid containing an aqueous medium, a viscosifying agent and a polyethylene oxide alkyl ether through a wellbore and into the subterranean formation, pressurizing the fracturing fluid to fracture the subterranean formation, and allowing the fracturing fluid to flow back into the wellbore from the subterranean formation. The polyethylene oxide alkyl ether useful in some embodiments is defined according to the formula:
Methods of fracturing a subterranean formation include introducing a fracturing fluid containing an aqueous medium, a viscosifying agent and a polyethylene oxide alkyl ether through a wellbore and into the subterranean formation, pressurizing the fracturing fluid to fracture the subterranean formation, and allowing the fracturing fluid to flow back into the wellbore from the subterranean formation. The polyethylene oxide alkyl ether useful in some embodiments is defined according to the formula:
Methods of fracturing a subterranean formation include introducing a fracturing fluid containing an aqueous medium, a viscosifying agent and a polyethylene oxide alkyl ether through a wellbore and into the subterranean formation, pressurizing the fracturing fluid to fracture the subterranean formation, and allowing the fracturing fluid to flow back into the wellbore from the subterranean formation. The polyethylene oxide alkyl ether useful in some embodiments is defined according to the formula:
where R1 and R2 are independently selected from linear or branched alkyl groups having from 2 to 16 carbon atoms, and ‘n’ may be a value selected from within a range of from 1 to 100.
A remote locking system for a blowout preventer (BOP) includes a locking mechanism configured to move to adjust the remote locking system between an unlocked configuration in which the remote locking system enables movement of a ram of the BOP and a locked configuration in which the remote locking system blocks movement of the ram of the BOP. The remote locking system also includes a gear assembly coupled to the locking mechanism, a motor coupled to the gear assembly, and an electronic controller configured to provide a control signal to activate the motor to drive the locking mechanism to move via the gear assembly.
Systems and methods presented herein include a downhole well tool having an electromechanical joint configured to connect to a downhole well tool component within a wellbore of an oil and gas well system. The electromechanical joint is configured to rotate to facilitate connection of the electromechanical joint to the downhole well tool component. For example, the electromechanical joint includes a main body portion, a rotating ring configured to rotate relative to the main body portion to facilitate connection of the electromechanical joint to the downhole well tool component, and a sealed electrical connection configured to couple with a mating electrical connection of the downhole well tool component.
A system for monitoring and optimizing fuel consumption by a genset at an oil rig is described. Gensets require large amounts of fuel to initiate and to maintain in a standby, idling position. The system accesses data in a drill plan to determine the present and future power requirements and initiates gensets if needed; otherwise gensets can be shut down. Excess power can be stored in a power storage unit such as a capacitor, battery, or a liquid air energy storage unit.
H02J 3/46 - Controlling the sharing of output between the generators, converters, or transformers
G05B 19/042 - Programme control other than numerical control, i.e. in sequence controllers or logic controllers using digital processors
H02J 7/14 - Circuit arrangements for charging or depolarising batteries or for supplying loads from batteries for charging batteries from dynamo-electric generators driven at varying speed, e.g. on vehicle
H02J 13/00 - Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
Systems and methods for monitoring and control in downhole well applications are provided. The system and methodology may be combined with a variety of completions or other types of well equipment deployed downhole to enable both electrical and fiber optic communication with downhole components. For example, the system enables both electrical and fiber optic communication for operating and monitoring of downhole completion systems or other systems.
A flow assurance digital avatar is provided that combines the simulation of fluid flow through a network of oilfield facilities including reservoirs, wells and pipelines, detection and visualization of possible flow-related issues and risks in the network of oilfield facilities, user evaluation of possible optimizations (what-if scenarios) in the operation of the network of oilfield facilities for fixes and workovers with respect to flow-related issues and risks, and user evaluation and management of possible tasks or actions for the fixes and workovers for the flow-related issues and risks. Other aspects are described and claimed.
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
E21B 47/10 - Locating fluid leaks, intrusions or movements
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
An ammonia production system includes a steam generation device configured to produce steam and an electrolyzer cell configured to produce hydrogen feedstock gas from the steam. A hydrogen combustor receives the hydrogen feedstock gas from the electrolyzer cell and combusts the hydrogen feedstock gas and produce heat and electricity. A combustion thermal conduit provides heat transfer between the hydrogen combustor and the steam generation device. An electrical generator is connected to the hydrogen combustor and configured to generate electricity.
Thermally induced graphene sensing circuitry and methods for producing circuits from such thermally induced circuits are disclosed along with applications to hydrocarbon exploration and production, and related subterranean activities. The thermally induced graphene circuitry advantageously brings electrically interconnections otherwise absent on oilfield service tools, enabling components and tools to become smart.
H05K 3/00 - Apparatus or processes for manufacturing printed circuits
B33Y 80/00 - Products made by additive manufacturing
C23C 18/02 - Chemical coating by decomposition of either liquid compounds or solutions of the coating forming compounds, without leaving reaction products of surface material in the coating; Contact plating by thermal decomposition
Systems and method presented herein enable the estimation of porosity using neutron-induced gamma ray spectroscopy. For example, the systems and methods presented herein include receiving, via a control and data acquisition system, data relating to energy spectra of gamma rays captured by one or more gamma ray detectors of a neutron-induced gamma ray spectroscopy logging tool. The method also includes deriving, via the control and data acquisition system, one or more spectral yields relating to one or more elemental components from the data relating to the energy spectra of the gamma rays. The method further includes estimating, via the control and data acquisition system, a measurement of porosity based on the one or more spectral yields relating to the one or more elemental components.
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 method may include receiving real-time data relating to drilling fluid for drilling operations that utilize a drilling fluid system that includes tanks and pumps, where the drilling operations include operations that pump the drilling fluid to a drill bit on a drillstring that rotates to extend a borehole in a formation, and where the drilling fluid flows to an annulus between the drillstring and the formation to apply pressure to the formation; detecting a tank state from a group of tank states based at least in part on the real-time data, where the group of tank states includes tank states defined with respect to one or more operations of the pumps; and detecting a change in tank volume, based at least in part on the tank state, as an indicator of an undesirable interaction between the drilling fluid and the formation
A method can include, responsive to receipt of a search instruction that includes one or more search criteria, accessing a data structure for subsurface geologic regions categorized at least in part according to parameters that describe depositional environments, where the data structure includes one or more includes virtual distances between the parameters; generating a search result using the one or more search criteria and the data structure, where the search result represents an organization of at least a portion of subsurface geologic regions as closest analogues to the one or more search criteria; and transmitting search result information for graphically rendering the search result to a display as part of an interactive graphical user interface.
A control system can include a controller that includes an interface for receipt of sensor data generated by sensors operatively coupled to a fluid flow system; memory that includes sets of tuning parameter values; and a loader that loads a selected set of the sets of tuning parameter values into the controller for issuance of control signals to a choke valve actuator for a choke valve of the fluid flow system according to the selected set of tuning parameter values and sensor data generated by one or more of the sensors.
The disclosure relates to an electrolysis system and method. The electrolysis system comprises a heating device for heating water above its boiling point (such as steam generator or flash desalinator) to produce a processed water product (such as steam or desalinated water). It also includes an electrolyzer that receives the processed water product to produce hydrogen gas and oxygen based on the processed water product. The system also includes a compressor that receives hydrogen gas and compresses the hydrogen gas, the compressor heating the hydrogen gas to a heated gas temperature; and a cooling system that cools the hydrogen gas from the heated gas temperature to a cooled temperature. The system also includes a heat transfer system that transfers absorbed heat from the cooling system to the heating device, the heating device producing the processed water product at least in part using the absorbed heat.
Multiphase flowmeter aperture antenna transmission and pressure retention are disclosed herein. An example apparatus includes at least one radiating element to transmit or receive an electromagnetic signal along a measurement plane orthogonal to a direction of flow of the fluid in the vessel; a pressure retaining member to prevent fluid from entering the aperture antenna assembly through a measurement window of the aperture antenna assembly, at least a portion of the pressure retaining member to separate the radiating element and the fluid; and a metal housing with or without slits, the pressure retaining member to be at least partially within the metal housing, the radiating element to be coupled to the metal housing.
G01F 1/58 - Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using electric or magnetic effects by electromagnetic flowmeters
A system can include one or more processors; memory; a data interface that receives data; a control interface that transmits control signals for control of pumps of a hydraulic fracturing operation; and one or more components that can include one or more of a modeling component that predicts pressure in a well fluidly coupled to at least one of the pumps, a pumping rate adjustment component that generates a pumping rate control signal for transmission via the control interface, a capacity component that estimates a real-time pumping capacity for each individual pump, and a control component that, for a target pumping rate for the pumps during the hydraulic fracturing operation, generates at least one of engine throttle and transmission gear settings for each of the individual pumps using an estimated real-time pumping capacity for each individual pump where the settings are transmissible via the control interface.
A dataset is received for ingestion into a data platform, and a correlation identifier is generated responsive to receiving the dataset. Multiple choreographed services emit multiple event messages. The plurality of choreographed services operate independently of each other based on a plurality of events triggered in a data platform. The plurality of events relate to contents of the dataset and comprising the correlation identifier. A message storage is populated with multiple status updates related to the correlation identifier. A status message associated with the correlation identifier is published in response to a status update of the plurality of status updates.
In some aspects, the techniques described herein relate to a bit. The bit includes a bit head formed from a first material. A connection portion is connected to the bit head opposite the bit head. The connection portion has a box connection having an inner surface with a threaded connection for connection to a drill string. A reinforcing ring is formed from a second material. The reinforcing ring is located at the connection portion to strengthen the connection portion. The reinforcing ring is connected to the connection portion with an interlocking feature.
An insertable flow meter assembly includes a flow measuring device configured to be inserted into a flow passage of a receiving structure. The flow measuring device is configured to enable determination of a flow rate of fluid through the flow passage, the flow measuring device is formed as a single continuous structure, and an outer cross-section of at least a portion of the flow measuring device is configured to be substantially the same as an inner cross-section of the flow passage. The insertable flow meter assembly also includes an end cap configured to engage an exterior surface of the receiving structure and to couple to the receiving structure at an end of the flow passage. The end cap is configured to block movement of the flow measuring device out of the end of the flow passage.
E21B 34/02 - Valve arrangements for boreholes or wells in well heads
E21B 47/10 - Locating fluid leaks, intrusions or movements
G01F 15/00 - MEASURING VOLUME, VOLUME FLOW, MASS FLOW, OR LIQUID LEVEL; METERING BY VOLUME - Details of, or accessories for, apparatus of groups insofar as such details or appliances are not adapted to particular types of such apparatus
62.
METHOD AND APPARATUS TO PERFORM A WIRELINE CABLE INSPECTION
Aspects of the disclosure provide for a method and apparatus to quickly identify defects in a cable used in hydrocarbon recovery wireline operations. A series of high-speed cameras take pictures along a length of the wireline cable, while artificial intelligence data processing algorithms process the camera data.
A bit may include a matrix portion, the matrix portion exposed at a cone region and a nose region of the bit. A bit may include a steel portion, the steel portion including a bit connection, the steel portion exposed at a gauge region of the bit. A bit may include a plurality of cutting elements secured to the matrix portion at the cone region and the nose region.
An expandable tool includes an expandable block set having a plurality of segments longitudinally arranged. Each segment of the plurality of segments has a segment configuration. The segment configurations of the expandable block are customized for a particular application, based on the anticipated formation type. During operation, the downhole segment wears or breaks away, exposing the uphole segment, which takes over as the primary segment.
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
E21B 7/28 - Enlarging drilled holes, e.g. by counterboring
A method can include receiving a request for loading a seismic volume; determining a loading order for portions of the seismic volume, where the loading order prioritizes an interior portion of the seismic volume over a boundary portion of the seismic volume; and transmitting, via a network interface, at least one of the portions of the seismic volume according to the loading order.
Methods include pumping a fracturing pad fluid into a subterranean formation under conditions of sufficient rate and pressure to create at least one fracture in the subterranean formation, the fracturing pad fluid including a carrier fluid and a plurality of bridging particles, the bridging particles forming a bridge in a fracture tip of a far field region of the formation. Methods further include pumping a first plurality of fibers into the subterranean formation to form a low permeability plug with the bridging particles, and pumping a proppant fluid comprising a plurality of proppant particles.
C09K 8/516 - Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
C09K 8/504 - Compositions based on water or polar solvents
C09K 8/508 - Compositions based on water or polar solvents containing organic compounds macromolecular compounds
C09K 8/514 - Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
C09K 8/80 - Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
E21B 33/138 - Plastering the borehole wall; Injecting into the formation
E21B 43/267 - Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
67.
METHODS USING DUAL ARRIVAL COMPRESSIONAL AND SHEAR ARRIVAL EVENTS IN LAYERED FORMATIONS FOR FORMATION EVALUATION, GEOMECHANICS, WELL PLACEMENT, AND COMPLETION DESIGN
Methods and systems are provided that perform sonic measurements in a high-angle wellbore or horizontal wellbore or vertical wellbore penetrating highly dipped formation layers where the formation layers can have a high degree of dip relative to the wellbore. Sonic data can be generated from the sonic measurements and processed using multiple arrival event processing to determine formation porosity, elastic rock properties and geometric information for a tool layer and nearby shoulder bed. Such information can be integrated into a 2D or 3D layered model of the formation. The elastic rock properties of the tool layer and shoulder bed derived from the multiple arrival event processing can provide more representative elastic property values, which can account for heterogeneity along the wellbore. Furthermore, the method can involve using at least part of the properties including porosity, elastic rock properties, and geometric information for the tool layer and shoulder bed for well placement (geosteering) and well completion optimization.
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 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
68.
ARTIFICIAL INTELLIGENCE TECHNIQUE TO FILL MISSING WELL DATA
A discriminator of a training model is trained to discriminate between original training images without artificial subsurface data and modified training images with artificial subsurface data. A generator of the training model is trained to: replace portions of original training images with the artificial subsurface data to form the modified training images, and prevent the discriminator from discriminating between the original training images and the modified training images.
A method includes receiving first data and building a first model of a well based at least partially upon the first data. The method also includes receiving second data and building a second model including a network of flowlines based at least partially upon the second data. At least one of the flowlines is connected to the well. The method also includes combining the first model and the second model to produce a combined model. The method also includes calibrating the combined model to produce a calibrated model. Calibrating the combined model includes receiving measured data, running a simulation of the combined model to produce simulated results, and adjusting a calibration parameter to cause the simulated results to match the measured data. The calibration parameter includes a productivity index of a fluid flowing out of the well. The method also includes updating the calibrated model to produce an updated model.
E21B 49/02 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by mechanically taking samples of the soil
Systems and methods presented herein include sidewall coring tools used to return core samples of rock from a sidewall of a wellbore as part of a data collection exercise for exploration and production of hydrocarbons. In particular, the systems and methods presented herein perform sidewall coring of a subterranean formation using a combination of rotary and percussive coring. More specifically, the systems and methods presented herein rotate a coring cylinder of a sidewall coring tool back and forth less than a full rotation while pushing the coring cylinder of the sidewall coring tool against a bore wall of a wellbore, and push the coring cylinder of the sidewall coring tool into the subterranean formation to enable extraction of a core sample of the subterranean formation.
E21B 49/06 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by mechanically taking samples of the soil using side-wall drilling tools or scrapers
71.
APPARATUS AND METHOD TO MEASURE FLARE BURNER FALLOUT
Methods, apparatus, systems, and articles of manufacture are disclosed to measure fallout from a liquid flare burner. An example apparatus includes a device configurator to invoke a first control valve to isolate the liquid flare burner from a test fluid source, and invoke a second control valve to fluidly couple the liquid flare burner to a hydrocarbon source to generate unburned fallout droplets to be captured by first and second measurement surfaces in first and second measurement regions, a parameter calculator to calculate first and second fallout volumes associated with the unburned fallout droplets captured by the first and second measurement surfaces, and determine a fallout efficiency of the liquid flare burner based on the first and second fallout volumes, and a burner configurator to, in response to the fallout efficiency not satisfying a fallout efficiency threshold, adjust a configuration of the liquid flare burner based on the fallout efficiency.
G01N 15/02 - Investigating particle size or size distribution
F23G 7/08 - Methods or apparatus, e.g. incinerators, specially adapted for combustion of specific waste or low grade fuels, e.g. chemicals of waste gases or noxious gases, e.g. exhaust gases using flares, e.g. in stacks
72.
SYSTEM AND METHOD FOR METHANE HYDRATE BASED PRODUCTION PREDICTION
This disclosure relates to techniques for determining a dissociation constant of a reservoir that includes methane hydrate and generating a methane hydrate production output that may be used to inform certain decisions related to processing a reservoir that includes the methane hydrate. In some embodiments, the techniques may include determining the dissociation constant using multiple pressures measured at different flowrates at time points from within a wellbore.
A back-up ring system incudes an outer C-ring, an inner C-ring that mates with the outer C-ring, the inner C-ring including a first rupture port, and a ring sheath that fits onto the inner C-ring, the ring sheath including a cut-out region, and a second rupture point. The inner C-ring further includes a blocking segment that angularly offsets the first and second rupture points. The cut-out region of the ring sheath mates with the blocking segment of the inner C-ring. The ring sheath further incudes a ‘7’ shaped cross-sectional profile.
A method can include receiving a request for field equipment data; responsive to the request, automatically processing the field equipment data using a trained machine learning model to generate a quality score for the field equipment data; and outputting the quality score.
Methods, computing systems, and computer-readable media for synchronizing data across a first application suite and an isolated second application suite. The method includes generating a first identity for a user to access data from a first application suite; generating a notification that the first identity has been created, causing a second application suite to generate a second different user identity to access data from the second application suite; authenticating a user based on authentication information and the first user identity; receiving, from the first application suite, a first resource from the user; storing the received first resource on the first application suite; synchronizing the first resource from the first application suite to the second application suite; synchronizing a second resource, stored on the second application suite, from the second application suite to the first application suite; and providing the second resource to the user via the first application suite.
A method includes acquiring blended seismic data representing a subsurface volume of interest from a plurality of seismic sources, estimating a signal mode using one or more first priors by applying sparse inversion to the blended seismic data, predicting multi-source interference in the blended seismic data based at least in part on the estimated signal mode, removing the estimated signal mode and the predicted multi-source interference from the blended seismic data, such that a residual signal is left, and estimating a coherent signal from the residual signal by solving a sparse inversion.
G01V 1/28 - Processing seismic data, e.g. analysis, for interpretation, for correction
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
A technique facilitates multiple actuations of a toe valve system positioned along a tubing string. According to an embodiment, the toe valve system comprises a piston sleeve slidably disposed in an outer housing which has at least one port therethrough. The toe valve system also may comprise a shifting sleeve shiftable between positions with respect to the at least one port. The piston sleeve may initially be held in a position closing off the at least one port to prevent flow between the interior and exterior of the tubing string. The piston sleeve is held in this closed position via a liquid trapped in a piston chamber which is located between the piston sleeve and the outer housing. The liquid, e.g. oil, is retained in the piston chamber by a release member, e.g. a rupture disc, until sufficient pressure is applied within the toe valve system and against the piston sleeve so as to actuate the release member and to thus allow outflow of liquid from the piston chamber.
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 34/12 - Valve arrangements for boreholes or wells in wells operated by movement of casings or tubings
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 34/08 - Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
A method can include receiving a request for field equipment data; responsive to the request, automatically processing the field equipment data using a trained machine learning model to generate a quality score for the field equipment data; and outputting the quality score.
Wellbore fluids may include an oleaginous continuous phase; a non-oleaginous discontinuous phase; and a polymeric amidoamine emulsifier stabilizing the non-oleaginous discontinuous phase in the oleaginous continuous phase, wherein the polymeric amidoamine emulsifier has at least 5 repeating units. Wellbore fluids may include an oleaginous continuous phase; a non-oleaginous discontinuous phase; and a polymeric amidoamine emulsifier stabilizing the non-oleaginous discontinuous phase in the oleaginous continuous phase, wherein the polymeric amidoamine emulsifier includes at least 3 repeating units selected from allylamine, polyaminopolyamide, N-alkyl acrylamides, (meth)acrylic acid, alkyleneamine reacted with a dicarboxylic acid, alpha-olefin-alt-maleic anhydride, styrene maleic anhydride, alkylene oxide, wherein one or more amine or acid group on the repeating unit is amidized.
Systems and methods provide a platform for a digital avatar that represents a particular physical device or a process using one or more processors and memory storing instructions. The instructions that, when executed by one or more processors, are configured to implement the digital avatar. The digital avatar includes a system model for the particular physical device or the process configured to receive data and to process the data to model other parameters or behaviors of the particular physical device or process. The digital avatar includes a model calibration module configured to calibrate the system model during operation of the particular physical device or process to provide an up-to-date evergreen model that is customized for the particular physical device or process due to changes in characteristics of the particular physical device or the process. The digital avatar is configured to ingest models into the platform, where the models are in one of multiple modeling frameworks and using one of multiple programming languages.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
A method for determining a screen break includes receiving a fluid stream from a screen system of a fluid system into a screen break detector, wherein the screen system comprises at least one screen, and the screen break sensor comprises a sample screen. The method also includes monitoring a fluid pressure of the fluid stream flowing through the sample screen of the screen break detector and detecting a condition of the at least one screen of the screen system based on the fluid pressure and one or more pressure thresholds. The method also may include outputting a notification of the condition of the at least one screen of the screen system. A system includes a screen break detector. The screen break detector includes a sample screen configured to receive a fluid stream from a screen system of a fluid system, wherein the screen system includes at least one screen and a pressure detector configured to monitor a fluid pressure of the fluid stream flowing through the sample screen.
Methods, computing systems, and computer-readable media for determining flow control device settings. The method may include obtaining data representing flow rates for a plurality of flow control devices; determining total molar rates for a plurality of flows through pipe segments associated with each of the flow control devices based on the obtained data; determining initial flow control device constraints based on the total molar rates for the plurality of flow control devices; determining that one or more wellhead constraints would be violated based on the flow control device constraints; determining adjusted flow control device constraints that result in the satisfaction of one or more wellhead constraints or constraints of others of the plurality of flow control devices; determining an adjusted flow rate based on the adjusted device constraints that satisfy the wellhead and the flow control device constraints; and executing a computer-based instruction to set one or more wellhead settings and flow control device valve settings based on the adjusted flow control device constraints.
A method can include accessing volumetric data from a data store, where the volumetric data correspond to a region; generating structured shape information for the region using at least a portion of the volumetric data; and, in response to a command from a client device, transmitting to the client device, via a network interface, a visualization data stream generated using at least a portion of the structured shape information.
An annular cutter catching device includes a housing having an inner bore therethrough, a cutter configured to cut a coupon, and a coupon catching device configured to grip an outer surface of the coupon. In an embodiment, an annular cutter catching device includes one or more split rings disposed within the inner bore of the housing. In the embodiment, at least one split ring is configured to grip an outer surface of the coupon within the inner bore of the housing. In an embodiment, an annular cutter catching device includes a coupon catcher disposed within the inner bore of the housing. In an embodiment, the coupon catcher includes a set of fingers movable between an open position and a closed position. In an embodiment, the set of fingers are configured to retain the coupon within the inner bore of the housing in the closed position.
Systems and methods are disclosed herein for improved wireline tension measurement and calibration in an oil-and-gas setting. An example method can include providing a machine-learning model configured to receive inputs associated with wireline tension. The inputs can include, for example, well-trajectory information, fluid density, fluid viscosity, toolstring type, cable type, and friction coefficient. The method can include providing some or all of those inputs and receiving an output from the machine-learning model of an estimated wireline tension. The method can also include receiving a second output of a wireline location recommended for measurement. A user can then perform a measurement at the suggested location and provide the measurement as an additional input to the machine-learning model.
B66D 1/50 - Control devices automatic for maintaining predetermined rope, cable, or chain tension, e.g. in ropes or cables for towing craft, in chains for anchors; Warping or mooring winch-cable tension control
G01L 5/04 - Apparatus for, or methods of, measuring force, work, mechanical power, or torque, specially adapted for specific purposes for measuring tension in flexible members, e.g. ropes, cables, wires, threads, belts or bands
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 19/084 - 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
86.
SPATIAL CHARACTERIZATION OF DYSFUNCTION IN DOWNHOLE SYSTEMS
Methods and systems are provided that determine data characterizing spatial variation of vibrational dysfunction (such as HFTO) along the BHA of a drilling system. In embodiments, such data can be determined from a minimal set of measurements of any or all of four variables that include: vibration amplitude; vibration wavelength; vibration frequency; and the axial position of the first vibrational node. In embodiments, such data can be determined from measurements of vibration amplitude and vibration frequency of a BHA at two fixed positions along the BHA (e.g., with two sensors offset axially along the BHA). In other embodiments, such data can be generated from the estimated position of the first vibrational node and measurements of vibration amplitude and vibration frequency by a single sensor disposed at a fixed axial position along the BHA.
Methods and systems are provided for controlling intermittent production of gas in association with liquids from a well. Production tubing disposed in the well provides a flow path for gas and liquids to the surface. An electrically-controlled choke and a controller are disposed at the surface. The choke is in fluid communication with the production tubing. The controller interfaces to the choke and executes autonomous control operations that control operation of the choke, wherein the autonomous control operations involve production cycles that include a production mode followed by a shut-in mode. In the production mode, the controller is configured to operate the choke in an open position. In the shut-in mode, the controller is configured to operate the choke in a closed position.
A technique facilitates actuation of a downhole device, such as an isolation valve. According to an embodiment, the downhole device may be in the form of an isolation valve member, e.g. a ball valve element, actuated between positions by a mechanical section which may comprise a shifting linkage. Actuation of the mechanical section, and thus actuation of the isolation valve member, is achieved by a trip saver section controlled according to a pressure signature which may be applied from a suitable location, e.g. from the surface. The trip saver section comprises a housing having an internal actuation piston coupled with the mechanical section. The trip saver section further comprises a pilot piston and a plurality of chambers formed in a wall of the housing and arranged to enable shifting of the actuation piston in response to a predetermined series of pressure pulses or other suitable pressure signature.
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
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
89.
DELIVERING APPLICATIONS VIA AN ON-DEMAND VIRTUAL MACHINE SYSTEM
Methods, computing systems, and computer-readable media for delivering applications using an on-demand virtual machine system. The method includes receiving an application request from a user, including a request to remotely access one or more applications; determining computing resources for fulfilling the application request; allocating the determined computing resources to the user from a client resource pool of a client to which the user is associated, wherein the allocating comprises serving a virtual machine (VM) allocated with the determined computing resources to the user; determining that the computing resources are no longer in use; and releasing the computing resources to the client resource pool.
A computer-implemented method for seismic processing includes receiving a seismic training input image, generating, using a first portion of a machine learning model, a first output based at least in part on the seismic training input image, generating, using a second portion of the machine learning model, a second output based at least in part on the seismic training input image, generating a loss function based at least in part on comparing at least two of the first output, a deterministic first label synthetically generated and representing a deterministic ground truth for the first output, the second output, and a non-deterministic second label representing a non-deterministic ground truth for the second output, and refining the first portion, the second portion, or both of the machine learning model based at least in part on the loss function.
A method, computing system, and computer-readable medium for navigating a geologic environment, in which the method includes obtaining first geological data representing a first location, correlating the first geological data with a chronostratigraphic timeline, receiving a selection of a second location, correlating second geological data representing the second location with the chronostratigraphic timeline, determining one or more characteristics of a geology of the second location based at least in part on the first geological data from the first location using the chronostratigraphic timeline, and visualizing a stratigraphic navigator representing the chronostratigraphic timeline and at least some of the second geological data for the second location.
A method can include receiving a digital operational plan that specifies computational tasks for seismic workflows, that specifies computational resources and that specifies execution information; dispatching instructions that provision the computational resources for one of the computational tasks for one of the seismic workflows; issuing a request for the execution information; receiving the requested execution information during execution of the one of the computational tasks using the provisioned computational resources; and, based on the received execution information indicating that the execution of the one of the computational tasks deviates from the digital operational plan, dispatching at least one additional instruction that provisions at least one additional computational resource for the one of the computational tasks for the one of the seismic workflows.
Methods, apparatus, systems, and articles of manufacture are disclosed to measure fallout from a liquid flare burner. An example apparatus includes a device configurator to invoke a first control valve to isolate the liquid flare burner from a test fluid source, and invoke a second control valve to fluidly couple the liquid flare burner to a hydrocarbon source to generate unburned fallout droplets to be captured by first and second measurement surfaces in first and second measurement regions, a parameter calculator to calculate first and second fallout volumes associated with the unburned fallout droplets captured by the first and second measurement surfaces, and determine a fallout efficiency of the liquid flare burner based on the first and second fallout volumes, and a burner configurator to, in response to the fallout efficiency not satisfying a fallout efficiency threshold, adjust a configuration of the liquid flare burner based on the fallout efficiency.
G01N 15/02 - Investigating particle size or size distribution
F23G 7/08 - Methods or apparatus, e.g. incinerators, specially adapted for combustion of specific waste or low grade fuels, e.g. chemicals of waste gases or noxious gases, e.g. exhaust gases using flares, e.g. in stacks
A method can include stochastically generating at least fifty realizations for a subsurface geologic environment by sampling distributions for a number of parameters that characterize the subsurface geologic environment, where the at least fifty realizations represent different results for an actual, physical characteristic of the subsurface geologic environment; ranking the number of parameters with respect to influence on the different results; and generating result predictions using a trained machine learning model for variations in values of at least the top ranked parameter, wherein the trained machine learning model is trained using at least a portion of the at least fifty realizations and their corresponding different results.
Systems and methods presented herein generally relate to a method that includes receiving water at a centralized facility. The method also includes receiving sand from one or more sand mines at the centralized facility. The method further includes receiving one or more chemicals at the centralized facility. In addition, the method includes using processing equipment of the centralized facility to process the water, the sand, and the one or more chemicals to produce a fracturing slurry. The method also includes conveying the fracturing slurry from the centralized facility to one or more fracturing sites.
A downhole drilling tool, forming part of a subterranean drilling system, may include at least one plate secured to an exterior of an elongate body. Electronics may be disposed between the plate and the body to be protected by the plate while still readily accessible. A dynamic element may be radially extendable from the plate to engage an inner wall of a borehole being drilled. If this radially-extendable element becomes worn or damaged from this engagement, the plate may be replaced. More expensive components of the drilling tool may be contained within the elongate body, rather than the plate, thus reducing replacement frequency. Additionally, plates including unique features may be employed at different times without altering the underlying elongate body.
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 10/633 - Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable with plural detachable cutting elements independently detachable
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
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
98.
INDUCED CIRCUITRY WITHIN A HARD DIAMOND-LIKE AND CARBON-RICH LAYER HAVING SENSING ABILITIES
A system may include a substrate and a coating deposited onto a surface of the substrate. The coating includes a carbon rich layer deposited on the substrate. The carbon rich layer is also characterized by a first carbon content including sp2 carbon and sp3 carbon. Further, the carbon rich layer includes one or more treated carbon regions. The one or more treated carbon regions possess an electrically conductive carbon material having a second carbon content including sp2 carbon and sp3 carbon. The second carbon content includes more sp2 carbon than the first carbon content, and may be pre-arranged and interconnected to produce an electrical circuitry with a pluralities of sensing abilities. The formed smart coating may be preferentially produced on a hard diamond-like carbon coating, such as a low friction and anti-scaling coating.
Methods, computing systems, and computer-readable media for dynamically adjusting drilling parameters during a drilling operation. The approach involves receiving, in real time, drilling parameter measurements and response measurements during a drilling operation. If the response measurements are below the lower limit of a window or trending downwards, the approach determines a new drilling parameter value that will increase the response measurement. The approach dynamically adjusts the drilling parameter value above the sectional limit, while still respecting hard limits. When the measured value improves, the approach returns the limit for the drilling parameter to the sectional limit.
A method can include receiving flow rate estimates from a computational, virtual flow meter at a wellsite; receiving flow rate measurements from a physical flow meter at the wellsite; and calling for calibration of the physical flow meter based on the flow rate estimates and the flow rate measurements.
patents
