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
2.
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 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
4.
METHODS, APPARATUS AND SYSTEMS FOR CREATING BISMUTH ALLOY PLUGS FOR ABANDONED WELLS
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 method can include generating a visual group of datasets; receiving a visualization mesh that intersects at least two of the datasets; executing a shader using graphics hardware to generate values for the visualization mesh, where the values depend on data within at least one of the at least two datasets; and rendering a visualization to a display using the values.
A downhole valve assembly includes a safety valve and an actuator that opens and/or closes the valve. The actuator can be an electro-hydraulic actuator (EHA), an electro mechanical actuator (EMA), or an electro hydraulic pump (EHP). The downhole safety valve can also include an electric magnet. The electric magnet can act as or control a magnetic decoupling mechanism to control closure of the safety valve.
A method for determining an uncertainty of a representation of a fault population includes receiving seismic data representing a subterranean domain. The subterranean domain includes a plurality of faults. The method also includes generating a plurality of fault volumes based upon the seismic data. The method also includes generating a plurality of fault populations based upon the fault volumes. The fault populations are generated by extracting one or more fault objects from one or more of the fault volumes. The method also includes generating quantitative values based upon the fault populations. The quantitative values represent on or more of the fault objects, one or more of the fault populations, or both. The method also includes comparing the quantitative values to determine the uncertainty of the representation of the fault populations. The method also includes generating or updating a visual representation based upon the comparison.
Embodiments presented provide for a method of monitoring emissions. A calibration of a metal oxide sensor is accomplished in order to monitor fugitive methane gas emissions on a consistent and constant basis.
A method of forward modeling reservoir fluid geodynamics that accounts for both slow processes and fast processes. The method provides a model that accounts for the fluid geodynamics from charge to current time.
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
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
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.
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 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.
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 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.
G01V 1/40 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
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
An inflatable packer assembly that includes opposing end fittings by which the inflatable packer assembly is installable within a downhole tool string. An inflatable body coupled between the end fittings has an external groove. An elongation sensor is fixed in the external groove. The elongation sensor includes a capacitive element that whose capacitance varies based on elongation of the elongation sensor in response to inflation of the inflatable body.
Systems and methods presented herein facilitate ensuring the integrity of oil and gas well intervention operations using blockchain technologies. In particular, the systems and methods described herein utilize blockchain technologies to ensure that all data relating to oil and gas well intervention operations are captured and stored in substantially real time during the operations in a secure and immutable manner.
E21B 47/125 - 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 earth as an electrical conductor
G05B 13/02 - Adaptive control systems, i.e. systems automatically adjusting themselves to have a performance which is optimum according to some preassigned criterion electric
H04L 9/00 - Arrangements for secret or secure communications; Network security protocols
A system for detecting hydrocarbons in a subterranean formation includes an outlet sensor configured to measure an outlet drilling fluid parameter of a drilling fluid. The system also includes an inlet sensor configured to measure an inlet drilling fluid parameter of the drilling fluid. The system also includes a gas extractor positioned downstream from the outlet of the wellbore and upstream from the inlet sensor. The gas extractor is configured to extract a gas from the drilling fluid. The system also includes a computing system configured to determine a first time when the outlet drilling fluid parameter increases by more than a first threshold, determine a second time when the inlet drilling fluid parameter becomes substantially constant or increases by more than a second threshold, and determine a surface transit time of the drilling fluid based at least partially upon the first time and the second time.
A method including parsing a natural language query to generate terms. The method also includes linking the terms to entities of a graph data structure including a first layer of nodes connected by edges. The entities are selected from among the nodes and the edges. The graph data structure further includes a meta layer which has tags associated with the edges and the nodes. The tags define an ontology for the entities. A term in the terms is linked to an entity in the entities when the term matches the entity. The method also includes generating a set of paths between selected tags in the meta layer. Each of the selected tags is associated with a corresponding edge in the graph data structure that matches a corresponding term extracted from the natural language query. The method also includes converting the set of paths into a structured query language statement.
Systems and methods presented herein a natural language query conversion framework configured to convert natural language queries into database-specific queries to enable users not particularly conversant in database query languages and schema. For example, a method includes receiving, via the natural language query conversion framework, a natural language query; converting, via the natural language query conversion framework, the natural language query into a database query using a language model (LM); and executing, via the natural language query conversion framework, the database query against an oil and gas (O&G) database.
A method can include receiving real-time data during a controlled drilling operation performed by a controller, an instrumented rig and a drillstring that includes one or more downhole sensors, where the data include surface data from the instrumented rig and downhole data from the one or more downhole sensors; detecting a drilling behavior during the drilling operation; and generating a control recommendation to mitigate the drilling behavior.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 47/18 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid
E21B 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 7/02 - Drilling rigs characterised by means for land transport, e.g. skid mounting or wheel mounting
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]
27.
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
Devices, systems, and methods are provided for a through-rotary centralizer for downhole operations. The through-rotary centralizer assists with centralizing a tool operating downhole, such as a bit. The through-rotary centralizer has a mandrel, a sleeve rotatably mounted around the mandrel, a floating hub slidably mounted around the sleeve, and centralizing arms mounted to the sleeve and floating hub. The centralizing arms extend to exert force against the inner wall of a tubular, such as wellbore casing, thereby providing stability to the downhole tool. Because the sleeve is rotatably mounted to the mandrel, the mandrel rotates within the sleeve and is able to transmit power or torque to the downhole tool, such as a bit. The centralizing arms are not required to rotate with the mandrel due to the rotatably mounted sleeve. A surface system may be used to control the position of the through-rotary centralizer.
A system and method for providing improved control of fluid flow between an interior and an exterior of a tubing string with a multicycle valve system. The multicycle valve having a run-in position, a fracturing position, and a production position. The multicycle valve comprising an outer housing having fracturing ports and production ports. The multicycle valve has a fracturing sleeve which is shifted via pressure applied to a first drop dissolvable ball to open fracturing ports of the multicycle valve. Pressure applied to a second dropped ball shifts an intermediate sleeve to close the fracturing ports and shifts a production sleeve to open production ports. The multicycle valve also has a bypass port allows sufficient fluid to exit the multicycle valve such that an additional ball pump-down operations can still take place uphole of the multicycle 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 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
E21B 43/267 - Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
35.
A METHOD TO ESTABLISH A DETECTABLE LEAK SOURCE LOCATION
Embodiments presented provide for a method for detecting emissions. The method establishes a map that is used with prevailing wind conditions to establish a point source location for methane gas emissions.
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
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
41.
INTERFEROMETRIC REDATUMING, INTERPOLATION, AND FREE SURFACE ELIMINATION FOR OCEAN-BOTTOM SEISMIC DATA
A method includes receiving a first seismic dataset based at least partially upon a signal. The signal is a subsea signal. The method also includes measuring one or more particle motion characteristics of the signal based at least partially upon the first seismic dataset. The method also includes separating the signal into an upgoing component, a downgoing component, and a direct arrival based on the one or more particle motion characteristics. The method also includes generating a propagation response between two or more of the sources based at least partially upon the downgoing component and the direct arrival. The method also includes generating a second seismic dataset based at least partially upon the propagation response.
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.
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 method includes receiving a first seismic dataset. The method also includes generating one or more particle motion characteristics of a signal based at least partially upon the first seismic dataset. The method also includes separating the signal into an upgoing component and a downgoing component based at least partially upon the one or more particle motion characteristics. The method also includes generating a second seismic dataset based at least partially up on the upgoing component, the downgoing component, or both. The second seismic dataset is denser than the first seismic dataset.
A method for generating resolved data is disclosed. The method receives captured data in a first signal space from sensors at a resource site and determines a signal characteristic associated with a first signal component, a second signal component, or a noise component within the captured data. The method transforms the captured data from the first signal space to a second signal space using a first transform operator. The method further extracts a first signal component from the transformed captured data in the second signal space. The extracted first signal component may be transformed back to the first signal space to generate a first extracted data which may be subtracted from the captured data. The method reconstructs the first extracted data to generate a first reconstructed data included in the resolved data. The resolved data includes a minimal amount of a noise component associated with the captured data.
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.
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
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
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 5/12 - 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 gamma- or X-ray sources
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
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
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 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 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
F04D 15/00 - Control, e.g. regulation, of pumps, pumping installations, or systems
G06Q 10/063 - Operations research, analysis or management
G05B 13/04 - Adaptive control systems, i.e. systems automatically adjusting themselves to have a performance which is optimum according to some preassigned criterion electric involving the use of models or simulators
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
60.
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
65.
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
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.
SYSTEMS AND METHODS FOR RECOVERING AND PROTECTING SIDEWALL CORE SAMPLES IN UNCONSOLIDATED FORMATIONS
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
G01N 1/04 - Devices for withdrawing samples in the solid state, e.g. by cutting
An electromagnetic telemetry system to support communications at an oilfield. The system may include unique modes of encoding and decoding acquired signal data between a downhole tool and a surface unit for attenuation of noise from the data. In one embodiment, a mode of speech separation may be utilized to further enhance reliability of the acquired signal data.
G01V 3/30 - 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 electromagnetic waves
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
70.
QUALITY ASSESSMENT OF DOWNHOLE RESERVOIR FLUID SAMPLING BY PREDICTED INTERFACIAL TENSION
Methods and systems that configure a downhole tool disposed within a wellbore adjacent a reservoir to perform fluid sampling operations that draw live reservoir fluid from the reservoir into the downhole tool are described. The live reservoir fluid is at elevated pressure and temperature conditions of the reservoir. The live reservoir fluid is analyzed within the downhole tool to determine fluid properties of the live reservoir fluid. Interfacial tension of the live reservoir fluid can be determined or predicted from the fluid properties of the live reservoir fluid. The interfacial tension of the live reservoir fluid can be used to characterize and assess quality of the live reservoir fluid in substantially real-time. The characterization and assessment of the quality of the live reservoir fluid can be used to control the sampling operations or initiate downhole fluid analysis or sample collection for analysis of "clean" reservoir fluid of acceptable quality.
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
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, 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
74.
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.
A method can include acquiring electromagnetic conductivity measurements for in-phase conductivity and quadrature conductivity using an electromagnetic conductivity tool disposed in a borehole of a formation that includes particles, where energy emissions of the electromagnetic conductivity tool polarize the particles; inverting a model, using the electromagnetic conductivity measurements, for at least two of salinity, water saturation, cation exchange capacity of the particles, Archie cementation exponent and Archie saturation exponent to characterize the formation, where the model includes (i) an in-phase conductivity relationship that depends on formation porosity and water saturation and (ii) a quadrature conductivity petrophysical relationship that depends on salinity, formation grain density, water saturation and cation exchange capacity of the particles; and transmitting the at least two to a computing framework for generation of at least one operational parameter for a borehole field operation for the borehole.
G01V 3/30 - 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 electromagnetic waves
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 fluid electrical probe includes a body portion housing a cleaner, a head portion forming a gap, an electrode disposed in the gap, and a temperature sensor disposed in the gap. The cleaner is extendable into the gap to clean the electrode and the temperature sensor. The body portion comprises a handle configured to be gripped by an operator.
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
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.
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.
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. The method further comprises generating the request responsive to accessing a project via a computational framework.
Monitoring and real-time adjustments of proppant concentrations during a hydraulic fracturing treatment may be advantageous, particularly when the goal is to create a heterogeneous proppant pack in the fracture. The proppant concentration may be measured by analyzing noise spectra as the fracturing fluid passes through a tubular body at the surface or downhole in the subterranean well.
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
92.
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
95.
METHODS FOR REAL-TIME OPTIMIZATION OF COILED TUBING CLEANOUT OPERATIONS USING DOWNHOLE PRESSURE SENSORS
Systems and methods presented herein facilitate coiled tubing cleanout operations, and generally relate to estimating reservoir pressure prior to the coiled tubing cleanout operations (e.g., while the wellbore is shut-in). For example, a method includes acquiring, via one or more downhole sensors of a coiled tubing system at least partially disposed within a wellbore, downhole data of the coiled tubing system; identifying, via a processing and control system, a density profile of fluids disposed within the wellbore based at least in part on the acquired downhole data; interpreting, via the processing and control system, the density profile of the fluids disposed within the wellbore; and estimating, via the processing and control system, a reservoir pressure of a reservoir through which the wellbore extends based at least in part on the interpreted density profile of the fluids disposed within the wellbore.
A system includes a drill pipe and a rotating control device including a housing defining a bore through which the drill pipe extends during a managed pressure drilling operation, a sealing element disposed in the housing that is configured to seal against the drill pipe to block fluid flow through an annular space surrounding the drill pipe, a bearing assembly disposed in the housing that enables the sealing element to rotate relative to the housing, and means for detecting eccentricity or misalignment of the drill pipe within the rotating control device during the managed pressure drilling operation.
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
G01V 1/40 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
E21B 47/013 - Devices specially adapted for supporting measuring instruments on drill bits
97.
METHODS AND SYSTEMS EMPLOYING AUTONOMOUS CHOKE CONTROL FOR MITIGATION OF LIQUID LOADING IN GAS WELLS
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 method can include acquiring data from a borehole imaging tool disposed in a borehole in a formation where the borehole includes electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining, based on the data, electrically insulating oil-based fluid impeditivity and a reference formation impeditivity via a circuit model that includes series and parallel terms; and detecting a location of a fracture in the formation based on a change in current flow from the tool through the electrically insulating oil-based fluid and into the formation by determining an effective formation impeditivity based on at least a portion of the data for the location and by comparing the effective formation impeditivity to the reference formation impeditivity.
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
G01V 3/02 - Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination or deviation operating with propagation of electric current
E21B 47/002 - Survey of boreholes or wells by visual inspection
G01V 1/40 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
99.
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.