A device includes a memory configured to store first executable code and a processor coupled to the memory. The processor is configured to calculate performance indicators for a sucker rod pump (SRP) based on performance data of the SRP, determine an operational frequency corresponding to operation of the SRP based on one performance indicator selected from the performance indicators, and initiate transmission of a control signal corresponding to the operational frequency to alter operation of the SRP to correspond to the operational frequency.
A sand screen for use within a wellbore. The sand screen may include a non-woven fiber polymer filter and a mechanical retainer. The non-woven fiber polymer filter may have a compressed state and an expanded state. The mechanical retainer may retain the non-woven fiber polymer filter in the compressed state. The non-woven fiber polymer filter may be expandable after exposure to a wellbore condition.
Systems and methods presented herein include coordinating behavior with independent winch systems and a wireline wellsite automation (WWA) platform, consisting of a variety of distributed services and applications, and that is completely separate from the independent winch systems, such that the coordination enables the WWA platform and an independent winch system to effect shutdown of the independent winch system, based on operating parameters received from the WWA platform and autonomous operating parameters transmitted to the independent winch system. For example, in certain embodiments, a WWA platform that is completely separate from a multiline unit winch system may be configured to continuously receive data relating to operating parameters and transmit control signals to the winch units of the multiline unit, in order to effect a multiline winch shutdown.
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
E21B 23/14 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for displacing a cable or a cable-operated tool, e.g. for logging or perforating operations in deviated wells
4.
DOWNHOLE SEGREGATION FOR WIRELINE FORMATION FLUID SAMPLING
The disclosure provides for a method for sampling fluid from a subterranean formation that is intersected by a wellbore. The method includes performing an initial draw-down at a target interval in the wellbore to pump fluid from the subterranean formation with a 3D radial probe. The method includes isolating the target interval of the wellbore with a packer and providing a residence time within a dead volume of the packer to allow fluid therein to separate into hydrocarbon and water phases. The method includes pumping a sample of the hydrocarbon into a sample chamber while pumping a remainder of the fluid into the wellbore, and testing the sample to determine a hydrocarbon content of the sample.
Embodiments presented provide for a method for using an imager to determine combustion efficiency measurement. In embodiments, a single-pixel multispectral imager is used to provide accurate measurements for combustion efficiency for flare and burner assemblies used in industry.
G01N 21/25 - ColourSpectral properties, i.e. comparison of effect of material on the light at two or more different wavelengths or wavelength bands
G01N 21/31 - Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry
G01N 33/00 - Investigating or analysing materials by specific methods not covered by groups
A method includes placing, via a bailer, a slurry into a wellbore to deposit a slurry downhole. The slurry includes a solids mixture and a fluid. The method also includes terminating placement of the slurry for a period of time. A viscous pill inhibits settling of the solids mixture, and the slurry displaces the viscous pill in contact with a surface of a screen.
A system includes one or more neutron sources configured to emit neutrons. The system also includes one or more electron detectors configured to detect electrons. Further, the system includes a control system comprising one or more processors. The control system is configured to determine a lithium concentration based on the electrons. Further, the control system is configured to generate a lithium extraction output based on the lithium concentration.
G01N 23/22 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by measuring secondary emission from the material
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
G01V 5/08 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
8.
SOURCE SEPARATION USING MULTISTAGE INVERSION WITH RADON IN THE SHOT DOMAIN
A method for processing seismic data includes receiving blended seismic data from one or more seismic sources. The method also includes applying a transform to the blended seismic data to decompose the blended seismic data into different parameters. The method also includes applying one or more independent sparse inversions to the different parameters. The method also includes defining a set of prior information techniques to be used within the one or more independent sparse inversions. The method also includes determining an energy part of the blended seismic data that is greater than a first predetermined threshold based at least partially upon the multiple independent sparse inversions, the set of prior information techniques, or both. The method also includes removing the energy part from the blended seismic data to produce modified seismic data.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spreadCorrelating seismic signalsEliminating effects of unwanted energy
G01V 1/28 - Processing seismic data, e.g. for interpretation or for event detection
G01V 1/32 - Transforming one recording into another
A compensation system may comprise an actuator sealed in a chamber. The chamber may comprise an actuator rod and a first bellow, wherein expansion of the first bellow is configured to extend the first bellow into a first cavity in the chamber, which moves the actuator rod towards the first cavity. The chamber may comprise a second bellow, wherein expansion of the second bellow is configured to extend the second bellow into a second cavity in the chamber. The first cavity is configured to be filled with dielectric fluid, the dielectric fluid moving between the first cavity and the second bellow based on a displacement caused by a movement of the actuator rod.
JAPAN ORGANIZATION FOR METALS AND ENERGY SECURITY (Japan)
Inventor
Du, Weijia
Kanno, Takayuki
Dollfus, Hadrien
Amour, Myriam
Abe, Shungo
Abstract
A method can include receiving real-time downhole time series sensor data during production of fluid from a well in fluid communication with a formation reservoir; transforming the real-time downhole time series sensor data to values for a set of predefined model features; detecting a downhole sand event using the values as input to a trained neural network model; and issuing a signal responsive to detection of the downhole sand event.
A device includes a memory configured to store first executable code and a processor coupled to the memory. The processor is configured to calculate performance indicators for a sucker rod pump (SRP) based on performance data of the SRP, determine an operational frequency corresponding to operation of the SRP based on one performance indicator selected from the performance indicators, and initiate transmission of a control signal corresponding to the operational frequency to alter operation of the SRP to correspond to the operational frequency.
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
E21B 47/009 - Monitoring of walking-beam pump systems
F04B 47/02 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps the driving mechanisms being situated at ground level
A method can include embedding a discontinuity as an object in a three-dimensional hexahedral grid that includes hexahedral cells and represents a geologic environment; cutting a number of the hexahedral cells by intersecting the object and the three-dimensional hexahedral grid to identify cut cells; constructing a topological three-dimensional hexahedral grid using a topology for the cut cells that includes spatially overlapping hexahedral cells and associated cut cell-face links; and generating results that characterize the geologic environment with the discontinuity using a system of equations that represent the geologic environment and the topological three-dimensional hexahedral grid.
Certain aspects of the disclosure provide a method of feasibility modeling for a plurality of geophysical monitoring tools. The method generally includes processing, using a flow simulation model configured to simulate carbon dioxide flow at a carbon capture and storage (CCS) site, model input parameters associated with the CCS site to generate flow simulation output data; extracting the flow simulation output data; processing the flow simulation output data to simulate a use of geophysical monitoring tools at the CCS site; for each geophysical monitoring tool: simulating a monitoring response; and determining a uncertainty level associated with the generated monitoring response; determining, using a Bayesian framework, a feasibility of implementing one or more of the plurality of geophysical monitoring tools at the CCS site based on the monitoring response and the uncertainty level associated with each of the geophysical monitoring tools and thereby generate a feasibility score for each tool.
A method including receiving, from a user device operated by a user, a request to access a pool of virtual machines. The virtual machines include a first subset of virtual machines and a second subset of virtual machines. The first subset of virtual machines are at a first provisioning level. The second subset of virtual machines includes a second provisioning level that is less than the first provisioning level. The request specifies a provisioning level request. The method also includes receiving a user profile associated with the user. The method also includes assigning, to the user, a selected virtual machine. The selected virtual machine is selected from among the first subset of virtual machines and the second subset of virtual machines based on the user profile and further based on the provisioning level request. The method also includes providing, to the user device, access to the selected virtual machine.
A method of operating a downhole motor on a downhole tool includes generating an electrical energy output with the downhole motor. The electrical energy output flows to an electronics system of the downhole tool. The method further includes applying an electrical energy input to the downhole motor with the electronics system. The method further includes reducing the electrical energy output based on the applied electrical energy input in order to maintain the electrical energy output below an operational threshold of the electronics system.
A communications framework can include a discussion tool operable within a process operations environment, where the discussion tool issues a request for communication with an expert and records contextual information of the process operations environment: a notification tool that, responsive to issuance of the request for communication, calls for issuance of a notification to an identified expert; and a recordation tool that calls for storage of communication information associated with communication with the identified expert to a database.
A packer assembly for use within a wellbore. The packer assembly may include a mandrel, a seal assembly disposed about the mandrel, and a deployment system disposed about the mandrel. The seal assembly may include a cup holder and a cup shaped sealing element coupled to the cup holder at a first end and deployable to create a seal between the mandrel and a wellbore wall. The deployment system may include a plurality of arc arms rotatingly coupled to the cup holder and a stack assembly that includes a plurality of packer elements that, when compressed, rotate the plurality of arc arms to deploy the cup shaped sealing element.
A dual tubing locating adapter (“DLTA”) for use with a mule shoe. The DLTA may include a housing, a primary tubing string, a lateral tubing string, and a retention mechanism. The primary tubing string may be positioned at least partially within the DLTA. The lateral tubing string may be positioned at least partially within the DLTA and retained within the DLTA via a shear mechanism. The retention mechanism may be operable to retain the lateral tubing string within the DLTA as the DLTA is landed on the mule shoe.
A method of stimulating a subterranean formation includes preparing an aqueous dispersion including one or more cellulosic nanoparticles. The cellulosic nanoparticles have respective surfaces functionalized with one or more hydrophilic polymers or ligands. one or more hydrophobic polymers or ligands, or a combination thereof. The method also includes pumping the aqueous dispersion into the subterranean formation.
C09K 8/90 - Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
20.
METHOD FOR DE-RISKING RESERVOIR ARCHITECTURE THROUGH SIMULATION OF FLUID CHARGE
Embodiments presented provide for a method for using down hole fluid measurements for hydrocarbon recovery operation. In embodiments, the down hole fluid measurements are used to determine reservoir features to aid in calculations for the reservoir. Downhole fluid measurements may also be used to check the accuracy of a downhole geological architecture and fluid charge parameters, thereby providing a check on geological conditions.
Embodiments presented provide for a method for defect recognition for pipes used in hydrocarbon recovery operations. In embodiments, a large foundation model is used to help automatically detect and characterize the defects, eliminating the need for expert analysis.
A method of operating a downhole system includes receiving trajectory data including a trajectory for steering a downhole tool toward a downhole target. The method includes identifying downhole tool data for the downhole tool. The method includes, based on the trajectory data and the downhole tool data, predicting one or more engineering metrics including one or more downhole tool metrics associated with an operation of the downhole tool in accordance with the trajectory and one or more completion metrics associated with a completion of the borehole at the downhole target. The method includes determining a coherency for the trajectory including determining whether the engineering metrics are within one or more predetermined thresholds. The method includes generating a report of at least some of the engineering metrics including a value of each engineering metric and an indication of whether the value is within the predetermined thresholds.
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 systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/022 - Determining slope or direction of the borehole, e.g. using geomagnetism
E21B 49/00 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
23.
TORSIONAL DAMPING AND FLEXIBLE COMPONENTS IN DOWNHOLE SYSTEMS AND METHODS
A flexible downhole component includes an upper connection for connecting the flexible downhole component to a first downhole tool and a lower connection for connecting the flexible downhole component to a second downhole tool. The flexible downhole component includes a flexible body disposed between the upper connection and the lower connection. The flexible downhole component includes an upper damping component and a lower damping component each configured to damp torsional oscillations.
Disclosed are a facility (100) and a method for providing process steam. The facility (100) comprises a first stage (6) for recovering waste heat in order to increase the temperature of a first heat-transfer fluid that is used to superheat an outlet fluid using a superheating device (8), and a second stage (7) for recovering waste heat in order to increase the temperature of a second heat-transfer fluid that is used to increase the temperature of the first heat-transfer fluid and/or of the outlet fluid.
F01K 3/14 - Plants characterised by the use of steam or heat accumulators, or intermediate steam heaters, therein having both steam accumulator and heater, e.g. superheating accumulator
F01K 3/18 - Plants characterised by the use of steam or heat accumulators, or intermediate steam heaters, therein having heaters
F22B 1/02 - Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers
Japan Organization for Metals and Energy Security (Japan)
Inventor
Du, Weijia
Kanno, Takayuki
Dollfus, Hadrien
Amour, Myriam
Abe, Shungo
Abstract
A method can include receiving real-time downhole time series sensor data during production of fluid from a well in fluid communication with a formation reservoir; transforming the real-time downhole time series sensor data to values for a set of predefined model features; detecting a downhole sand event using the values as input to a trained neural network model; and issuing a signal responsive to detection of the downhole sand event.
Embodiments presented provide for a method for performing waveform processing. In one embodiment, a synthetic dictionary is created and then, using a machine learning process, data is processed to produce a result.
Methods and systems are provided for monitoring operational characteristics of a drilling system that includes a bottom hole assembly having a drill collar operably coupled to a drill bit. A device having an elongate beam and at least one pair of sensors is rigidly secured to a part of the bottom hole assembly to measure strain in the part of the bottom hole assembly. The measurement of strain can be used to derive a measurement of at least one operational parameter of the drilling system, such as dog leg severity of a wellbore, torque on bit, and/or weight on bit.
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 systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/013 - Devices specially adapted for supporting measuring instruments on drill bits
G01L 5/00 - Apparatus for, or methods of, measuring force, work, mechanical power, or torque, specially adapted for specific purposes
A wellhead container for a geothermal system includes a base configured to engage a bottom of a recess within a ground. The recess extends vertically from the bottom of the recess to a surface of the ground, the base includes at least one first opening, and the at least one first opening is configured to receive a drilling string. The wellhead container includes a top configured to support a load applied by a drilling machine to the wellhead container. The top includes second openings, and each second opening is configured to receive the drilling string. The wellhead container includes a sidewall extending along a vertical axis between the base and the top. The sidewall is configured to position an upper surface of the top substantially flush with the surface of the ground, and the sidewall is configured to transfer at least a portion of the load to the base.
F24T 10/10 - Geothermal collectors with circulation of working fluids through underground channels, the working fluids not coming into direct contact with the ground
29.
SYSTEM AND METHOD FOR PERFORMING DRILLING TRAJECTORY PLANNING
A method of operating a downhole system includes receiving trajectory data including a trajectory for steering a downhole tool toward a downhole target. The method includes identifying downhole tool data for the downhole tool. The method includes, based on the trajectory data and the downhole tool data, predicting one or more engineering metrics including one or more downhole tool metrics associated with an operation of the downhole tool in accordance with the trajectory and one or more completion metrics associated with a completion of the borehole at the downhole target. The method includes determining a coherency for the trajectory including determining whether the engineering metrics are within one or more predetermined thresholds. The method includes generating a report of at least some of the engineering metrics including a value of each engineering metric and an indication of whether the value is within the predetermined thresholds.
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 systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
Embodiments presented provide for a method for using down hole fluid measurements for hydrocarbon recovery operation. In embodiments, the down hole fluid measurements are used to determine reservoir features to aid in calculations for the reservoir. Downhole fluid measurements may also be used to check the accuracy of a downhole geological architecture and fluid charge parameters, thereby providing a check on geological conditions.
E21B 49/02 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by mechanically taking samples of the soil
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
Embodiments presented provide for a method for performing waveform processing. In one embodiment, a synthetic dictionary is created and then, using a machine learning process, data is processed to produce a result.
22 into a solvent to a regenerator of a solvent carbon capture system or process. Other heating sources within the carbon capture system may also be integrated to transfer heat to the regenerator.
B01D 53/14 - Separation of gases or vapoursRecovering vapours of volatile solvents from gasesChemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by absorption
A porous structural thermoset media is described herein. A method includes dispensing particles of a removable material into a mold, dispensing a structural thermoset material into the mold, curing the structural thermoset material having the particles of the removable material disposed therein to generate a cured structural thermoset material having the particles of the removable material disposed therein, and removing the particles of the removable material from the cured structural thermoset material to generate a porous structural thermoset.
Methods and systems are provided for monitoring operational characteristics of a drilling system that includes a bottom hole assembly having a drill collar operably coupled to a drill bit. A device having an elongate beam and at least one pair of sensors is rigidly secured to a part of the bottom hole assembly to measure strain in the part of the bottom hole assembly. The measurement of strain can be used to derive a measurement of at least one operational parameter of the drilling system, such as dog leg severity of a wellbore, torque on bit, and/or weight on bit.
E21B 47/007 - Measuring stresses in a pipe string or casing
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
E21B 44/04 - Automatic control of the tool feed in response to the torque of the drive
35.
SCREW CONVEYOR ADSORPTION MOVING BED WITH HEAT INTEGRATION
Systems and methods presented herein provide for a screw conveyor adsorption moving bed that separates carbon dioxide from a gas mixture. Adsorbent particles are transported between an adsorption section of the reactor, which can be an outer column, and a desorption section, which can be an inner column. The particle transport is facilitated by the screw conveyor located inside the inner column. The screw conveyor is specially designed to have a hollow screw, shaped as a spiral surface, attached to a central shaft. The screw surface is also equipped with plurality of holes and a flexible edge attachment to seal against the cylindrical surface. The hollow shape allows the gas to flow from the inlet of the shaft to the particles through the holes on the screw, thus creating uniform gas distribution.
B01D 53/06 - Separation of gases or vapoursRecovering vapours of volatile solvents from gasesChemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with moving adsorbents
B65G 33/14 - Screw or rotary spiral conveyors for fluent solid materials comprising a screw or screws enclosed in a tubular housing
Systems and methods presented herein provide for a box chain conveyor adsorption moving bed that separates carbon dioxide from a gas mixture. A box chain conveyor is oriented around a wall, including a chain that moves in a closed loop around the wall. One side of the box chain conveyor is in an adsorption section and an opposite second side is in a desorption section. Particle boxes contain adsorbent particles, and the chain moves the particle boxes around the wall in the closed loop. Heated gas passes through the desorption section, causing CO2 to desorb from particle boxes in the desorption section. Desorbed CO2 is expelled from an output.
B01D 53/08 - Separation of gases or vapoursRecovering vapours of volatile solvents from gasesChemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with moving adsorbents according to the "moving bed" method
B01D 53/04 - Separation of gases or vapoursRecovering vapours of volatile solvents from gasesChemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
37.
DETECTING ANOMALIES AND PREDICTING FAILURES IN PETROLEUM-INDUSTRY OPERATIONS
Systems and methods for detecting anomalies and predicting failures in petroleum-industry operations, using Machine Learning. Systems and methods are provided for determining system anomalies and individual resource anomalies using trained models and predicting estimated system times to failure based thereon. Features correlated to system failures may be identified in a root cause analysis and used to perform forecasting to determine when a failure is likely to occur. The forecasting may include determining when one or more components may likely meet certain thresholds associated with failures of the components. A protective action may be performed to protect resources associated with the operations, based on determining the length of time until system failure of the operation is estimated to occur.
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
38.
AUTOMATED METHOD AND SYSTEM TO DETECT SEGMENT ROCK PARTICLES
Systems and methods are provided for analyzing sample images, such as for rock particles obtained during drilling of a geologic formation. The system and techniques utilize a Large Foundation Model (LFM) in the segmentation of rock particles. The LFM can receive an image (or image data) of rock particles as an input and generates segmentation of the image at a pixel level (i.e., each pixel of the image is classified) as a segmented image. Additionally, active annotation can be provided in conjunction with a graphics user interface (GUI) to allows for user interaction with images as well as selective segmentation of the images.
E21B 49/00 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
G06F 3/04817 - Interaction techniques based on graphical user interfaces [GUI] based on specific properties of the displayed interaction object or a metaphor-based environment, e.g. interaction with desktop elements like windows or icons, or assisted by a cursor's changing behaviour or appearance using icons
G06V 10/77 - Processing image or video features in feature spacesArrangements for image or video recognition or understanding using pattern recognition or machine learning using data integration or data reduction, e.g. principal component analysis [PCA] or independent component analysis [ICA] or self-organising maps [SOM]Blind source separation
G06V 10/82 - Arrangements for image or video recognition or understanding using pattern recognition or machine learning using neural networks
Systems and methods presented herein facilitate coiled tubing operations, and generally relate to wirelessly configuring bottom hole assemblies (BHAs) for use in coiled tubing well operations. For example, certain embodiments of the present disclosure include a method that includes wirelessly communicatively coupling at least one user computing device to a wireless access point of a wireless access module of a BHA. The method also includes wirelessly receiving one or more command signals from the at least one user computing device via the wireless access point of the wireless access module of the BHA. The method further includes adjusting one more operating settings or procedures of one or more downhole tool components of the BHA based at least in part on the one or more command signals.
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
A method includes receiving a plurality of seismic data. The method also includes generating a plurality of seismic reports each having an arrangement of different subsets of the plurality of seismic data. Further, the method includes determining a quality score associated with each seismic report of the plurality of seismic reports. Further still, the method includes generating a seismic data filtering model based on the quality scores of the plurality of seismic reports, wherein the seismic data filtering model stores relationships between the quality scores and the seismic data.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spreadCorrelating seismic signalsEliminating effects of unwanted energy
41.
METHODS FOR CONFIDENCE ASSESSMENT WITH FEATURE IMPORTANCE IN DATA DRIVEN ALGORITHMS
Embodiments presented provide for a method for establishing a confidence assessment for data. Data may be segregated by features importance during the confidence assessment, allowing evaluators the ability to determine the quality of data being processed by the method. The method may comprise performing a principal compoenent analysis on k model original features to obtain k principal components representing uncorrelated input data distributions, wherein k is an integer. The method may also comprise computing feature importance weights for each of the k principal component inputs. The method may also comprise identifying any new sample data in-distribution to weighted probabilities compared to assigned cut-offs.
Systems and techniques for establishing tool location in a well and conveyance line characteristics of a conveyance line accommodating the tool. The systems and techniques are directed at a closed loop manner of acquiring well location information. Thus, multiple pass detections of a well feature may be utilized to map, update and/or provide well location information in addition to conveyance line characteristic information in real-time. This may occur in absence of prior stored well mapping information or with supplemental information thereof.
E21B 17/04 - CouplingsJoints between rod and bit, or between rod and rod
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
G01V 1/40 - SeismologySeismic or acoustic prospecting or detecting specially adapted for well-logging
G01V 5/12 - Prospecting or detecting by the use of ionising 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
Systems and methods for maintaining wellsite equipment are presented herein. For example, an integrated digital factory and maintenance system is configured to receive data relating to maintenance tasks for wellsite equipment at a maintenance shop in substantially real-time during performance of the maintenance tasks; to calculate a plurality of yield metrics, each yield metric of the plurality of yield metrics corresponding to respective maintenance stages of the maintenance tasks in substantially real-time during performance of the maintenance tasks; and to provide the plurality of yield metrics via a graphical user interface displayable via a display device. In addition, the integrated digital factory and maintenance system is configured to calculate a predicted turnaround time for the maintenance tasks based on the plurality of yield metrics; and to provide the predicted turnaround time via the graphical user interface.
A fluid testing system includes an enclosure, a fluid container within the enclosure, and a passageway formed in a wall of the fluid container. The fluid testing system also includes a suction pump coupled to the passageway and configured to pump a sample fluid through the passageway to provide a positive level for the sample fluid in an interior chamber of the fluid container.
A method includes setting a target value for a coordinate direction of a depositional space to define a cutting plane that cuts a depogrid cell at the target value in the coordinate direction. The method further includes generating a cutting polygon that bounds a planar region of the cutting plane to define a cutting surface at the target value that subdivides the depogrid cell into a plurality of depogrid cells in the coordinate direction. The cutting surface provides common planar surfaces between the plurality of depogrid cells in the depositional space. The method further includes transforming the cutting surface to a geological space using vertices of the cutting polygon and a correspondence mapping that defines a relationship between depositional coordinates and geological coordinates. The cutting surface provides common non-planar surfaces between the plurality of depogrid cells in the geological space.
Systems and methods for wireless deployment of electrical lower completions are provided. A wet disconnect tool-running tool includes a battery and telemetry section, and electronics and sensors section, and a pressure compensator and control lines section.
E21B 47/14 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
F16L 51/00 - Expansion-compensation arrangements for pipe-lines
47.
ENHANCED QUALITY BOREHOLE IMAGE GENERATION AND METHOD
Methods for enhancing borehole images that learning patterns from historical borehole recorded mode image logs for a given basin to enhance real-time borehole images, use style characteristics from one example borehole recorded mode image to enhance real-time borehole images; optimize downhole data for transmission leveraging the presence of image enhancement frameworks on the surface, or combinations thereof.
A packer assembly for use within a wellbore. The packer assembly may include a mandrel, a seal assembly disposed about the mandrel, an anti-extrusion assembly disposed about the mandrel proximate the seal assembly to prevent extrusion of the seal assembly, and a deployment system. The anti-extrusion assembly may include a cradle cone that may include a plurality of arcuate surfaces on an exterior of the cradle cone and a plurality of cradle arms. Each cradle arm may include a flexible tip and be positioned on a respective arcuate surface of the cradle cone. The deployment system may be operable to compress the seal assembly such that the seal assembly seals against a wellbore wall and to rotate the plurality of cradle arms such that the flexible tips of the cradle arms contact the wellbore wall to prevent extrusion of the seal assembly.
Processes and systems for automating a conveyance operation using an elongated conveyance member. In some embodiments, the process can include modeling one or more system state profiles of a downhole tool string during the conveyance operation within a wellbore to define one or more profile models; calibrating the one or more profile models; using the one or more calibrated profile models to calculate at least one of a tension profile and a force profile along the elongated conveyance member based, at least in part, on one or more detectable system states and/or one or more undetectable system states; and using one of: (i) a surface tension uncertainty quantification model to calculate a surface tension and uncertainty bounds around the calculated surface tension; or (ii) a surface weight uncertainty quantification model to calculate a surface weight and uncertainty bounds around the calculated surface weight.
The present disclosure relates to the application of machine learning algorithms to recommend one or more tools for completion of a well, based on the features of the well. Predictive models may be built with the functionality of recommending one or more tools for a particular well completion. When the predictive models recommend the use of a tool, secondary predictive models may further recommend a particular tool selected from a group of tools. The predictions may achieve a high level of accuracy, and as such, may be used to recommend tools for well completion.
Systems and methods for maintaining wellsite equipment are presented herein. For example, an integrated digital factory and maintenance system is configured to receive data relating to maintenance tasks for wellsite equipment at a maintenance shop in substantially real-time during performance of the maintenance tasks; to calculate a plurality of yield metrics, each yield metric of the plurality of yield metrics corresponding to respective maintenance stages of the maintenance tasks in substantially real-time during performance of the maintenance tasks; and to provide the plurality of yield metrics via a graphical user interface displayable via a display device. In addition, the integrated digital factory and maintenance system is configured to calculate a predicted turnaround time for the maintenance tasks based on the plurality of yield metrics; and to provide the predicted turnaround time via the graphical user interface.
Systems and methods of the present disclosure provide systems and methods for performing downhole formation testing operations. Certain methods include deploying a downhole toolstring of a downhole formation testing system to a downhole location within a wellbore extending through a subterranean formation, wherein the downhole toolstring includes a single packer positioned near a lower end of the downhole toolstring; setting the single packer within the wellbore to isolate one or more zones of interest of the subterranean formation in a lower portion of the wellbore below the single packer from an upper portion of the wellbore above the single packer; and, after setting the single packer within the wellbore, using the downhole toolstring to perform downhole formation testing on one or more fluids received from the one or more zones of interest by the downhole toolstring.
Systems and methods are provided to analyze rock cuttings and measure physical lithological features of the rock cuttings. An image analysis workflow is provided, which includes multiple computational modules to automatically estimate relevant geological information from rock cuttings. Reference data, manual descriptions, and well log values are associated and used to determine rock properties of the rock cuttings. A software is developed for the image analysis, and results are displayed in various views.
E21B 49/00 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
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 systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
G06V 10/40 - Extraction of image or video features
G06V 10/764 - Arrangements for image or video recognition or understanding using pattern recognition or machine learning using classification, e.g. of video objects
54.
METHODS AND COMPUTING SYSTEMS FOR GEOSCIENCES AND PETRO-TECHNICAL COLLABORATION
Computing systems and methods for geosciences collaboration are disclosed. In one embodiment, a method for geosciences collaboration includes obtaining a first set of geosciences information from a first computer system of the plurality of computer systems; distributing the first set of geosciences information from the first computer system to at least a second computer system; receiving a user input from the second computer system of the plurality of computer systems, the user input entered manually by a user; providing the user input to the first computer system; in response to providing the user input to the first computer system, receiving a revised set of geosciences information from the first computer system; and repeating the receiving a user input, the providing the user input, and the receiving the revised set of geosciences information until the revised set of geosciences information is determined to satisfy accuracy criteria.
G06F 3/01 - Input arrangements or combined input and output arrangements for interaction between user and computer
G06F 3/04815 - Interaction with a metaphor-based environment or interaction object displayed as three-dimensional, e.g. changing the user viewpoint with respect to the environment or object
A progressive cavity pump system may comprise a progressive cavity pump (PCP) configured to be deployed in a wellbore, an electric motor, wherein the PCP is configured to rotate at the same speed as the electric motor, and a first portion of the pumping system is configured to be replaced, via a tensile element, without replacing a second portion of the pumping system. The first portion may comprise the PCP and the second portion may comprise the motor.
Systems and methods presented herein facilitate well operations, and generally relate to wirelessly configuring bottom hole assemblies (BHAs) for use in such well operations. For example, certain embodiments of the present disclosure include a method that includes wirelessly communicatively coupling at least one user computing device to a wireless access point of a wireless access module of a BHA. The method also includes wirelessly receiving one or more command signals from the at least one user computing device via the wireless access point of the wireless access module of the BHA. The method further includes adjusting one more operating settings or procedures of one or more downhole tool components of the BHA based at least in part on the one or more command signals.
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
E21B 47/26 - Storing data down-hole, e.g. in a memory or on a record carrier
57.
METHOD AND APPARATUS TO MEASURE PRESSURIZED DENSITY IN A SAMPLING LOOP
Methods and apparatus for measuring pressure density of a fluid are described herein. A system herein includes a fluid pathway; a pressure sensor coupled to the fluid pathway; a density sensor coupled to the fluid pathway; and a volume reduction device coupled to the fluid pathway. A method herein includes circulating a fluid through a fluid pathway; closing a first valve in the fluid pathway; closing a second valve in the fluid pathway; using a volume reduction device located in the fluid pathway between the first valve and the second valve to increase pressure of the fluid; measuring pressure of the fluid in the fluid pathway between the volume reduction device and one of the first valve and the second valve; and measuring a density of the fluid in the fluid pathway between the volume reduction device and one of the first valve and the second valve.
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
G01N 9/26 - Investigating density or specific gravity of materialsAnalysing materials by determining density or specific gravity by measuring pressure differences
A method can include calibrating a model using pressure and flow rate data to generate a calibrated model; receiving an upstream pressure value and a downstream pressure value that define a pressure differential across a flow device; and computing a flow rate through the flow device using the upstream pressure value, the downstream pressure value and the calibrated model.
G01F 25/10 - Testing or calibration of apparatus for measuring volume, volume flow or liquid level or for metering by volume of flowmeters
G01F 1/34 - 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 mechanical effects by measuring pressure or differential pressure
G01F 1/74 - Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid
G01F 15/00 - Details of, or accessories for, apparatus of groups insofar as such details or appliances are not adapted to particular types of such apparatus
Embodiments presented provide for a jarring device. The jarring device is used in downhole environments during hydrocarbon recovery operations. Embodiments also provide a method for safe use of a jarring device to enable freeing stuck components without damaging wireline equipment.
E21B 31/107 - Fishing for or freeing objects in boreholes or wells using impact means for releasing stuck parts, e.g. jars
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
60.
POLE-MOUNTED DEVICES AND SYSTEMS FOR IOT-ENABLED MONITORING OF METHANE EMISSIONS OF ONE OR MORE INDUSTRIAL FACILITIES
The disclosure relates to an emissions detector for monitoring methane emissions at one or more industrial facilities. The emissions detector includes: a pole; an enclosure mounted on the pole, wherein the enclosure houses at least one sensor, wherein the at least one sensor includes a gas sensor configured to measure concentration of methane in atmospheric gas that flows into the enclosure; and means for removably securing the pole to ground without the use of concrete.
Systems and methods presented herein facilitate operation of well-related tools. In certain embodiments, a variety of data (e.g., downhole data and/or surface data) may be collected to enable optimization of operations related to the well-related tools. In certain embodiments, the collected data may be provided as advisory data (e.g., presented to human operators of the well to inform control actions performed by the human operators) and/or used to facilitate automation of downhole processes and/or surface processes (e.g., which may be automatically performed by a computer implemented surface processing system (e.g., a well control system), without intervention from human operators). In certain embodiments, the systems and methods described herein may enhance downhole operations (e.g., milling operations) by improving the efficiency and utilization of data to enable performance optimization and improved resource controls of the downhole operations.
E21B 10/44 - Bits with helical conveying portion, e.g. screw type bitsAugers with leading portion or with detachable parts
E21B 17/04 - CouplingsJoints between rod and bit, or between rod and rod
E21B 17/20 - Flexible or articulated drilling pipes
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
62.
SINGLE TRIP COMPLETION SYSTEM WITH OPEN HOLE GRAVEL PACK GO/STOP PUMPING
A method of completing a well in a single trip includes drilling a wellbore with drilling mud, running a single trip completion string including an upper completion, a lower completion, and a packer between the upper and lower completions into the wellbore, displacing the wellbore to solids free fluid by opening or closing a circulation sliding sleeve disposed below the packer in the lower completion, opening the circulation sliding sleeve and spotting gravel slurry in a casing annulus, closing the circulation sliding sleeve and pumping the gravel slurry down the casing annulus into an open hole annulus while taking returns through a base pipe of a sand control assembly and production tubing of the single trip completion string, opening the circulation sliding sleeve, displacing the cased hole section to completion fluid, closing the circulation sliding sleeve, and setting the packer.
Embodiments presented provide for a method for establishing a confidence assessment for data. Data may be segregated by features importance during the confidence assessment, allowing evaluators the ability to determine the quality of data being processed by the method.
A fluid health manager may measure fluid health parameters related to bit balling health. A fluid health manager may apply a bit balling model to each of the fluid health parameters to generate a bit balling health rating of the AF, the bit balling model including a parameter weight for the each of the fluid health parameters. A fluid health manager may based on the bit balling health rating, preparing a drilling fluid recommendation to maintain or improve the bit balling health.
E21B 43/16 - Enhanced recovery methods for obtaining hydrocarbons
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
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
65.
SYSTEMS AND METHODS FOR MANAGING DRILLING FLUID HEALTH
A fluid health monitoring system may measure fluid health parameters related to NAF emulsion stability. A fluid health monitoring system may apply a stability model to each of the fluid health parameters to generate an emulsion stability rating of the NAF, the stability model including a parameter weight for the each of the fluid health parameters. A fluid health monitoring system may based on the emulsion stability rating, preparing a drilling fluid recommendation to maintain or improve the NAF emulsion stability.
E21B 49/00 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
Systems and methods for regulating head tension in a wireline system are described herein. A head tension control system may determine a head tension based on a speed of the tool driving equipment and a cable speed of the cable as a function of an operation of the winch. A head tension regulation error may be determined based on a comparison of the head tension and a target head tension, and the head tension control system may operate the winch or the tool driving equipment according to an operating zone that includes the head tension regulation error. The operating zone may be defined by a first range of values for a difference between the speed of the tool driving equipment and the cable speed, and a first range of values for a difference between the head tension and the target head tension.
A method can include performing a reservoir simulation for injection of carbon dioxide into a reservoir via an injection well: during the performing, accessing a trained machine learning model that outputs hydrate information based on reservoir conditions; and, based on the hydrate information, generating reservoir simulation results that indicate an amount of the carbon dioxide sequestered in the reservoir.
A non-pressure sensitive (“NPS”) module. The NPS module may include a mandrel, a lug assembly, a release sleeve, and a retention mechanism. The mandrel may have fluid pathways that balance pressure uphole of the mandrel and downhole of the mandrel when the NPS module is positioned within the borehole. The lug assembly may extend at least partially through the mandrel, a lug of the lug assembly extendable through a port in the liner hanger to prevent setting of the liner hanger when the lug assembly is in a run-in position. The release sleeve may be coupled to the lug assembly and operable to shift the lug assembly from a run-in position to an intermediate position that allows the liner hanger to be set. The retention mechanism may be operable to prevent the lug assembly from shifting to a retracted position until run-in tool is pulled uphole.
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 43/10 - Setting of casings, screens or liners in wells
69.
INTEGRATED SCREEN FOR ELECTRICAL FLOW CONTROL VALVE
A screen is integrated with or connected to an electric flow control valve via a flow-through 3-way sub, wherein the 3-way sub comprises: a first connection configured to couple to the electric flow control valve; a second connection configured to couple to the screen; a third connection configured to couple to an inner string disposed at least partially within the screen; and one or more flow through ports configured to direct flow from the electric flow control valve to an annulus of the screen.
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 17/042 - CouplingsJoints between rod and bit, or between rod and rod threaded
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
A cutting element may include a substrate having a base. A cutting element may include an ultrahard layer bonded to the substrate, the ultrahard layer formed from an ultrahard material, the ultrahard layer including: a side surface adjacent to the base, the side surface including a plurality of cutting surfaces; and an upper surface extending into the ultrahard layer.
Systems and techniques for establishing tool location in a well and conveyance line characteristics of a conveyance line accommodating the tool. The systems and techniques are directed at a closed loop manner of acquiring well location information. Thus, multiple pass detections of a well feature may be utilized to map, update and/or provide well location information in addition to conveyance line characteristic information in real-time. This may occur in absence of prior stored well mapping information or with supplemental information thereof.
A fluid health manager may measure fluid health parameters related to sag health of the NAF. A fluid health manager may apply a sag health model to each of the fluid health parameters to generate a sag health rating of the NAF, the sag health model including a parameter weight for the each of the fluid health parameters. A fluid health manager may based on the sag health rating, preparing a drilling fluid recommendation to maintain or improve the sag health.
Techniques and systems for reservoir characterization. One embodiment includes receiving first raw data corresponding to at least one attribute of a well, applying a pre-processing operation to correct at least one error in the first raw data to generate prepared data, transmitting the prepared data to a machine learning system; training the machine learning system into a trained machine learning system using the prepared data, and generating a final model via the trained machine learning system, wherein the final model operates to generate a characterization of a reservoir in a subsurface region of Earth when second raw data is input to the final model.
G01V 5/12 - Prospecting or detecting by the use of ionising 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
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
Embodiments presented provide for a jarring device. The jarring device is used in downhole environments during hydrocarbon recovery operations. Embodiments also provide a method for safe use of a jarring device to enable freeing stuck components without damaging wireline equipment.
A cutting element may include a substrate having a base. A cutting element may include an ultrahard layer bonded to the substrate, the ultrahard layer formed from an ultrahard material, the ultrahard layer including: a side surface adjacent to the base, the side surface including a plurality of cutting surfaces; and an upper surface extending into the ultrahard layer.
A zero-flaring well testing assembly is provided. The zero-flaring well testing assembly can be coupled to receive a gas-containing well effluent from a wellhead assembly. The zero-flaring well testing assembly can include a flowmeter and at least one multiphase pump. The zero-flaring well testing assembly can also be coupled to a production line to provide at least a gas-containing portion of the well effluent to the production line without flaring gas of the well effluent. Additional systems, methods, and devices are also disclosed.
A general-purpose workflow for automatic borehole sonic data classification to identify data into different physical categories and logging conditions, which are traditionally manually evaluated. The workflow uses machine learning techniques and physical knowledge for data classification, including pre-processing the high-dimensional high-quality dispersion modes extracted using a recently developed physical-driven ML enabled approach.
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 method can include receiving remarks associated with one or more field operations; processing the remarks for event detection using a dependency matcher and a machine learning model, where, responsive to the dependency matcher failing to detect an event, the processing implements the machine learning model to detect the event; and outputting at least the detected event.
G06Q 10/04 - Forecasting or optimisation specially adapted for administrative or management purposes, e.g. linear programming or "cutting stock problem"
Systems and methods presented herein generally relate to a formation testing platform for quantifying and monitoring deep transient testing (DTT) surface gas rates formation testing data collected by a downhole well tool, which may be adjusted based on surface gas rates directly measured by surface equipment. For example, a method includes flowing one or more fluids from a subterranean formation to flow through a downhole well tool disposed in a wellbore of a well during a deep transient testing (DTT) operation performed by the downhole well tool. The method also includes measuring data related to one or more properties of the one or more fluids using one or more downhole fluid analysis sensors disposed within the downhole well tool, and predicting, via a control system, a first predicted DTT surface gas rate based on the data measured related to the one or more properties of the one or more fluids.
Systems and methods presented herein provide for cutting in a borehole or casing. A cutting device can include a first arm having a cutting blade, wherein the cutting blade has side cutting teeth and an axis of rotation that is substantially at a right angle with respect to an axis of the tool body. The cutting device can also include a second arm with a bumper. The first and second arms articulate away from the elongate body in different directions to reduce vibrations while cutting. A control device can automate the cut based on hydraulic pressure measurements. Additionally, the cutting device can also be extended or rotated on a rotary index. The cutting device can rotate around a J slot, in an example.
E21B 29/00 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground
A well intervention system includes a housing. A first annular packer and a second annular packer are positioned in the housing and are configured to seal against a conduit. A lubricant injection port extends through the housing to a cavity defined between the first annular packer and the second annular packer. A pressure release port extends through the housing to the cavity, and a pressure release valve is configured to be selectively actuated to enable release of pressure from the cavity through the pressure release port.
A steering system may include a steering unit having a plurality of steering pads and a steering connection. A steering system may include a bit having a gauge diameter and a bit connection, the bit connecting to the steering unit at the bit connection and the steering connection, the bit including a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.
A steering unit may include a housing. A steering unit may include a plurality of actuator supports arranged circumferentially around the housing. A steering unit may include an actuator pad extending through the housing. A steering unit may include a cutting element connected to the housing between two of the plurality of actuator supports.
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutterDrill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
A method includes placing, via a bailer, a slurry into a wellbore to deposit a slurry downhole. The slurry includes a solids mixture and a fluid. The method also includes terminating placement of the slurry for a period of time. A viscous pill inhibits settling of the solids mixture, and the slurry displaces the viscous pill in contact with a surface of a screen.
Systems and methods presented herein generally relate to a formation testing platform for quantifying and monitoring deep transient testing (DTT) surface gas rates formation testing data collected by a downhole well tool, which may be adjusted based on surface gas rates directly measured by surface equipment. For example, a method includes flowing one or more fluids from a subterranean formation to flow through a downhole well tool disposed in a wellbore of a well during a deep transient testing (DTT) operation performed by the downhole well tool. The method also includes measuring data related to one or more properties of the one or more fluids using one or more downhole fluid analysis sensors disposed within the downhole well tool, and predicting, via a control system, a first predicted DTT surface gas rate based on the data measured related to the one or more properties of the one or more fluids.
Processes and systems for microseismic event detection. In some embodiments, the process can include acquiring seismic data with a dense seismic receiver array; converting seismic data into an image domain dataset; detecting one or more seismic waveform edges; characterizing within the image domain dataset one or more linear segments which each define a portion of one or more of the one or more seismic waveform edges, and wherein the linear segments are functions of one or more seismic arrival times and one or more subterranean depths; and estimating the subterranean depth of the one or more microseismic events within a subterranean formation based on the one or more linear segments.
Process for locating emission detecting camera(s) at a worksite. The process can include creating a site model, completing a camera coverage calculation loop that can include choosing a first camera location from the site model, and completing a source calculation loop to provide a plurality of coverage values of the first camera location for a plurality of potential emission sources in the site model. The process can also include calculating a coverage ratio from the plurality of coverage values to provide a first coverage ratio. The process can also include repeating the camera coverage calculation loop for an additional potential camera location from the site model to provide a plurality of coverage ratios. The process can also include creating an ordered list of the potential camera locations based on the coverage ratios. The process can also include choosing a camera position at the worksite from the ordered list.
A device for directional drilling includes a body, an actuatable steering pad, an actuator, and a cutting element. The body has a rotational axis. The actuator moves the actuatable steering pad radially outward from the body between an open position and a closed position, and the actuatable steering pad has a contact surface. The cutting element is positioned on the actuatable steering pad with a radially outermost portion of the cutting element radially outward of a radially outermost portion of the contact surface in the closed position and radially inward of the radially outermost portion of the contact surface in the open position.
E21B 10/32 - Drill bits with leading portion, i.e. drill bits with a pilot cutterDrill bits for enlarging the borehole, e.g. reamers with expansible cutting tools
A device may include a housing, wherein the housing has a longitudinal axis. A device may include a magnet rotationally fixed to the housing. A device may include a rotational mass supported in the housing and rotatable relative to the housing around a rotational axis with a magnetic field of the magnet penetrating the rotational mass, the rotational mass including an electrically conductive material that produces an eddy current when translated relative to the magnetic field.
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
A magnetic parking brake for use in a downhole telemetry tool includes first and second magnets disposed, or spring biased into magnetic engagement with one another. An electromagnetic and/or mechanical mechanism is configured to reduce the magnetic engagement and thereby release the brake.
E21B 41/00 - Equipment or details not covered by groups
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
F16D 63/00 - Brakes not otherwise provided forBrakes combining more than one of the types of groups
F16D 121/20 - Electric or magnetic using electromagnets
This disclosure is directed to drilling tools and, more specifically, drilling bits. One such bit includes a bit body comprising a first gauge pad and a second gauge pad. The bit further includes a first blade comprising a leading portion and a trailing portion, wherein the leading portion is disposed on the first gauge pad with a negative helix angle and the trailing portion is disposed on the second gauge pad with a positive helix angle.
The present disclosure describes a method may include receiving input data comprising geological data, an indication of a set of components to be placed in a layout for the site, and an emission cost estimate for each of the set of components. The method may also include defining uncertainty parameters and generating a plurality of planning scenarios to implement based on the components and uncertainty parameters. Additionally, the method may include determining facility placements, well trajectories, pipeline placements, and a net present value for each of the planning scenarios. Further, the method may include calculating a tax credit for each of the planning scenarios, ranking each of the planning scenarios based on a respective net present value and a respective tax credit to generate a ranked list of the plurality of planning scenarios, and generating a visualization comprising the ranked list of the planning scenarios.
93.
METHOD OF CUSTOMER SENTIMENT ANALYSIS USING LOGS AND FEEDBACK
A method implements customer sentiment analysis using logs and feedback. Log data is received. The log data is processed with a text generation model to generate synthesized text. The synthesized text is processed with a sentiment prediction model to generate a sentiment prediction. The sentiment prediction model is trained with a training label received responsive to a similarity score of a training vector meeting a similarity threshold. The sentiment prediction is presented.
G06F 18/2135 - Feature extraction, e.g. by transforming the feature spaceSummarisationMappings, e.g. subspace methods based on approximation criteria, e.g. principal component analysis
G06F 18/241 - Classification techniques relating to the classification model, e.g. parametric or non-parametric approaches
G06Q 30/02 - MarketingPrice estimation or determinationFundraising
A control system for controlling pressure of fluid within a wellbore includes a rotating control device (RCD). a distribution manifold, a choke and kill (CK) manifold, and a managed pressure drilling (MPD) manifold fluidly connected with each other, a sensor operable to facilitate fluid measurements indicative of a property of the fluid, and a controller communicatively connected with the distribution manifold and the sensor. The controller is operable to receive the fluid measurements, cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the MPD manifold to thereby permit the MPD manifold to control the pressure of the fluid within the wellbore, and cause the distribution manifold to direct the fluid discharged out of the wellbore via the RCD to flow through the CK manifold to thereby permit the CK manifold to control the pressure of the fluid within the wellbore.
A method includes receiving a seismic survey that includes a plurality of seismic slices. The method also includes converting the seismic slices into an embedding. The embedding includes one or more vectors. Each of the vectors includes more than 3 dimensions. The method also includes generating a plot based at least partially upon the embedding.
Embodiments presented provide for a method for identification of defects in geological stratum, called vugs. The identification of the vugs is performed on data from high resolution oil-based mud images obtained from wireline and/or drilling activities.
G01V 3/38 - Processing data, e.g. for analysis, for interpretation or for correction
G01V 3/28 - Electric or magnetic prospecting or detectingMeasuring magnetic field characteristics of the earth, e.g. declination or deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device using induction coils
G06V 10/24 - Aligning, centring, orientation detection or correction of the image
G06V 10/44 - Local feature extraction by analysis of parts of the pattern, e.g. by detecting edges, contours, loops, corners, strokes or intersectionsConnectivity analysis, e.g. of connected components
G06V 10/50 - Extraction of image or video features by performing operations within image blocksExtraction of image or video features by using histograms, e.g. histogram of oriented gradients [HoG]Extraction of image or video features by summing image-intensity valuesProjection analysis
G06V 10/764 - Arrangements for image or video recognition or understanding using pattern recognition or machine learning using classification, e.g. of video objects
Systems and methods presented herein facilitate automation of coiled tubing drilling (CTD) operations. For example, a computer-implemented method includes performing a drilling operation via a CTD system; detecting data relating to one or more operating parameters of the drilling operation via one or more sensors of the CTD system during the drilling operation; and automatically adjusting at least one adjustable operating parameter of the drilling operation based on the detected data during the 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 systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
Systems and methods are described for an automatic and adaptive scanning method to efficiently scan for gas plumes using an imaging or LiDAR based gas monitoring system. In an example, the gas monitoring system can be coupled to a laser absorption spectroscopy with LiDAR. In an example, systems and methods for optimizing the utilization of the imaging or LiDAR based gas monitoring system includes planning, commissioning, acquiring data automatically, interpreting the data, or extracting gas emission events from the data, or a combination thereof, to provide a complete lifecycle of a gas leak and a comprehensive understanding of the gas emissions. In another example, systems and methods for detecting the presence of a plume of gas includes using supervised machine learning to train a model to recognize which images contain plumes of gas and estimate corresponding rates of gas leakage based on the images.
A system includes processing circuitry and a non-transitory, computer-readable medium that includes instructions that cause processing circuitry to receive logging data regarding a fluid. The logging data is indicative of a plurality of isotope ratios of a plurality of alkanes of the fluid. The instructions also cause the processing circuitry to determine, based on at least a first isotope ratio of the plurality of isotope ratios of the logging data corresponding to a first alkane of the plurality of alkanes, a thermal maturity of the fluid. Additionally, the instructions cause the processing circuitry to determine, based on at least a second isotope ratio of the plurality of isotope ratios corresponding to a second alkane of the plurality of alkanes, a gas-oil ratio (GOR) of the fluid. Furthermore, the instructions cause the processing circuitry to cause display of the thermal maturity of the fluid and the GOR of the fluid.
Systems and methods presented herein facilitate coiled tubing operations, and generally relate to reduction of shock and vibrations to portions of the coiled tubing string. A device includes a first end configured to be disposed downstream of a bottom hole assembly of a coiled tubing drilling string; a second end configured to be disposed downstream of the first end and upstream of a drive of the coiled tubing drilling string; and a moveable valve configured to move from a first position to a second position to divert at least a portion of drilling fluid flow away from the drive when the drilling fluid flow is greater than a preset flow value or a weight on bit is less than a preset weight value and thereby reduce a rotation rate of the drive.
