A monitoring system includes a first transducer component configured to couple to a running tool that is configured to place an insert into a housing and a second transducer component configured to couple to the housing. One of the first transducer component or the second transducer component is configured to emit acoustic waves, and the other one of the first transducer component or the second transducer component is configured to output sensor signals indicative of a received portion of the acoustic waves. The monitoring system also includes one or more processors configured to determine that the insert is in a landed position in the housing based on the sensor signals.
E21B 47/095 - Locating or determining the position of objects in boreholes or wells; Identifying the free or blocked portions of pipes by detecting acoustic anomalies, e.g. using mud-pressure pulses
E21B 33/04 - Casing heads; Suspending casings or tubings in well heads
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
A method can include constructing a numerical model of a material matrix, where the numerical model includes cells; performing a simulation of physical phenomena with respect to time using the numerical model; during the performing, analyzing one of the cells as to physical characteristics of the material matrix; and, responsive to the analyzing and during the performing, assigning one or more properties to the cell that indicate failure of the material matrix of the cell without removing the cell from the numerical model.
A subsurface representation may define subsurface configuration of a subsurface region. A grid connectivity graph for the subsurface representation may include (1) nodes that represent cells within the subsurface representation, and (2) edges between the nodes that represent connectivity between the cells within the subsurface representation. The grid connectivity graph may be filtered to remove edges that do not satisfy a connectivity criterion. The filtered grid connectivity graph may be used to compute a linear solver preconditioner that improves the performance of the subsurface simulation.
A method for optimizing a seismic survey design includes obtaining a well trajectory, determining a depth range and a measurement interval for the seismic survey, determining an optimal seismic shot position for each receiver within the depth range using an inverse function, determining one or more potential seismic shot configurations that each include a number of seismic shots, a location for each of the number of seismic shots, and a power of each of the seismic shots, determining an estimate of a data quality for each of the determined one or more potential seismic shot configurations using an objective function, and determining an optimum seismic survey design based on the determined estimated data quality for each of the determined one or more potential seismic shot configurations, wherein the estimated data quality for the optimum seismic survey design is greater than a predetermined minimum threshold.
Embodiments presented provide for a method and apparatus for testing a sample fluid for asphaltene deposition. The apparatus provides two testing cylinders and a transfer pump to transfer fluid from the first cylinder to the second cylinder and back again while pressure is varied on the testing fluid, while a spectrometer evaluates the fluid during the pressure variation.
Methods and systems are provided for automating well completion selection and design using machine learning and natural language processing. The present disclosure describes a method for designing a well completion, comprising: i) collecting and storing a historical dataset comprising unstructured data related to prior well completions; ii) identifying a plurality of unstructured schematic documents related to prior well completions that are a part of the historical dataset of i); iii) processing each given unstructured schematic document of the plurality of unstructured schematic documents of ii) to generate structured data corresponding to text of the given unstructured schematic document; iv) associating the structured data corresponding to text of the respective unstructured schematic documents of iii) with different well contexts as part of a database; and v) presenting a graphical user interface to a user for designing a well completion, wherein the graphical user interface presents structured data stored in the database of iv) for insight in designing the well completion.
G06F 30/27 - Design optimisation, verification or simulation using machine learning, e.g. artificial intelligence, neural networks, support vector machines [SVM] or training a model
G06F 16/31 - Indexing; Data structures therefor; Storage structures
G06F 30/12 - Geometric CAD characterised by design entry means specially adapted for CAD, e.g. graphical user interfaces [GUI] specially adapted for CAD
G06F 30/13 - Architectural design, e.g. computer-aided architectural design [CAAD] related to design of buildings, bridges, landscapes, production plants or roads
A system can include edge devices that include communication circuitry; and one or more security components. A method can include receiving security codes from a plurality of edge devices without accessing the Internet; comparing the security codes without accessing the Internet; and, based at least in part on the comparing, connecting the plurality of edge devices for communication without accessing the Internet. A method can include executing a trained machine learning model on an edge device; and, based at least in part on the executing, detecting a change in state of the edge device.
H04L 41/12 - Discovery or management of network topologies
H04L 41/22 - Arrangements for maintenance, administration or management of data switching networks, e.g. of packet switching networks comprising specially adapted graphical user interfaces [GUI]
H04L 67/289 - Intermediate processing functionally located close to the data consumer application, e.g. in same machine, in same home or in same sub-network
H04L 9/32 - Arrangements for secret or secure communications; Network security protocols including means for verifying the identity or authority of a user of the system
8.
SYSTEM AND METHOD FOR EVALUATING BOTTOM HOLE ASSEMBLIES
A method for evaluating one or more bottom hole assemblies (BHAs) includes receiving a plurality of inputs. The inputs include one or more properties of the one or more BHAs, a planned trajectory of a wellbore, and one or more properties of a subterranean formation into which the wellbore will be drilled. The method also includes simulating drilling the wellbore in the subterranean formation based at least partially upon the inputs. Drilling of the wellbore is simulated with one or more artificial intelligence (AI) agents. Drilling of the wellbore is simulated a plurality of times using each of the one or more BHAs, thereby producing a plurality of simulations. Each simulation is generated using a different one of the AI agents. The method also includes generating one or more outputs in response to simulating drilling the wellbore.
Systems and methods for power recovery in carbon capture and storage applications are provided. Such systems and methods include ESP systems including permanent magnet motors (PMM) or induction motors (IM). Systems and methods for power generation including permanent magnet motor electric submersible pumps are also provided.
A method automatically validates sensor data. The method includes extracting a sample from a sample time series using a sample window, generating an input vector from the sample, and generating a context vector from the input vector using an encoder model comprising a first recurrent neural network. The method further includes generating an output vector from the context vector by a decoder model comprising a second recurrent neural network and generating a reconstruction error from a comparison of the output vector to the input vector. The reconstruction error indicates an error with the sample. The method further includes presenting the reconstruction error.
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 1/28 - Processing seismic data, e.g. analysis, for interpretation, for correction
G06F 11/22 - Detection or location of defective computer hardware by testing during standby operation or during idle time, e.g. start-up testing
G06F 11/263 - Generation of test inputs, e.g. test vectors, patterns or sequences
G06N 3/04 - Architecture, e.g. interconnection topology
11.
SINGLE-PHASE RETARDED ACID SYSTEMS USING AMINO ACIDS
Treatment of hydrocarbon formations using single-phase aqueous acid blends that contain arginine is described herein. The single-phase aqueous fluid includes one or more strong acid molecules and arginine in water, wherein the one or more strong acid molecules are present in a concentration range of 7.5 wt% to 28 wt%, based on the weight of the aqueous fluid, and arginine is present in a molar ratio of arginine to the one or more strong acid molecules that is from 1:100 to 1:5.
Systems are provided for capturing carbon dioxide that includes a water source supplying a flow of source water, a gas source supplying a flow of source gas, a carbonation chamber, sensors, and a controller. The chamber has a first inlet fluidly coupled to the water source by a first valve, a second inlet fluidly coupled to the gas source by a second valve, and an outlet. The sensors measure fluid properties for i) source water that flows into the chamber, ii) fluid within the chamber, and iii) fluid that exits the chamber. The controller is configured to automatically control the first and second valves based on evaluation of time-series data representing the measured fluid properties to provide flows of the source water and the source gas into the chamber that produces a continuous carbonation reaction in the chamber concurrent with fluid outflow from the chamber.
A platform is provided for implementing a digital representation of a particular industrial asset. The platform is configured to create an avatar corresponding to the particular industrial asset from at least one model and an avatar template, wherein the avatar template refers to or incorporates the at least one model or part thereof, and the avatar is created from the avatar template and refers to or incorporates the avatar template or part thereof; execute a simulation that refers to or incorporates the avatar or part thereof, wherein execution of the simulation uses the at least one model of the avatar template referenced or incorporated by the avatar along with operational data corresponding to the particular industrial asset to generate a digital representation of the particular industrial asset.
A platform and method are provided for implementing a digital representation of a particular industrial asset, which includes at least one model, an avatar template that refers to or incorporates the at least one model or part thereof, and an avatar corresponding to the particular industrial asset. The avatar is created from the avatar template and refers to or incorporates the avatar template or part thereof. A simulation refers to or incorporates the avatar or part thereof. Execution of the simulation uses the at least one model of the avatar template referenced or incorporated by the avatar along with operational data corresponding to the particular industrial asset to generate a digital representation of the particular industrial asset that is customized for the particular industrial asset due to changes in characteristics of the particular industrial asset over time.
ABSTRACT A continuous choke for a flow control valve is provided. The continuous choke can be included in a fully electric, full bore flow control valve. The continuous choke comprises a housing comprising at least one opening, a sleeve comprising at least one opening aligned with the at least one opening of the housing, a piston slidable relative to the sleeve to progressively cover or uncover the at least one opening of the sleeve to progressively decrease or increase, respectively, flow through the continuous choke, wherein the piston is configured to slide distally relative to the sleeve to move toward a closed position, the piston comprising a plurality of channels configured to direct fluid flow.
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
16.
SYSTEMS AND METHODS FOR MODELING A SUBSURFACE VOLUME USING TIME-LAPSE DATA
A method for modeling a subsurface volume using time-lapse data includes receiving a baseline seismic dataset, a baseline property model, a monitoring seismic dataset, and a monitoring property model, sorting the baseline seismic dataset and the monitoring seismic dataset into respective common gathers, representing offset, time, and depth point, extracting signal data for a range of depth points for the baseline dataset and a signal data for a corresponding range of depth points for the monitoring seismic dataset, predicting a property model change based at least in part on the signal data for the range of depth points of the baseline seismic dataset and the monitoring seismic dataset, using a machine learning model, and generating a property model representing a subsurface volume based at least in part on the property model change predicted using the machine learning model.
A sand screen joint for use with a control line. The sand screen joint may include a shroud having a channel extending longitudinally across the shroud and a control line clamp coupled to the shroud. The control line clamp may include a base having a profile that aligns with the channel of the shroud and a lid that engages with the base to retain the lid in a closed position and to retain the control line within the control line clamp.
A method can include receiving a number of samples of liquid production values and associated gas-lift injection rates for one of one or more wells; determining a prospective optimal gas-lift injection rate for the one of the one or more wells via a regression that fits the number of samples; responsive to the prospective optimal gas-lift injection rate satisfying one or more gas-lift injection rate criteria, issuing an instruction to implement the prospective optimal gas-lift injection rate for the one of the one or more wells; receiving a new sample as a measured liquid production value for the implemented prospective optimal gas-lift injection rate and responsive to satisfaction of one or more compliance criteria; and replacing one of the number of samples with the new sample.
The present disclosure relates to systems, non-transitory computer-readable media, and methods for detecting a washout or other anomaly event in a wellbore. In particular, in one or more embodiments, the disclosed systems receive a plurality of measurements including a measured flow rate into the wellbore, a measured weight on a drill bit in the wellbore, a measured depth of the drill bit in the wellbore, and a measured pressure at a standpipe of the wellbore. In one or more embodiments, the disclosed systems estimate one or more parameters of a physical model for determining a theoretical estimate of the standpipe pressure. In one or more embodiments, the disclosed systems determine a probability that the washout or other anomaly event is occurring in the wellbore based at least partially upon the measurements and the theoretical estimate of the standpipe pressure.
A method for seismic surveying includes receiving a baseline dataset and a plurality of sparse monitoring datasets, generating a decimated baseline dataset by removing one or more sources, receivers, or both from the baseline dataset, generating a reconstructed baseline dataset by inputting the decimated baseline dataset into a machine learning model, generating reconstructed monitoring datasets by inputting the plurality of sparse monitoring datasets to the machine learning model, the machine learning model having been trained based on a comparison of the reconstructed baseline dataset to the baseline seismic dataset, determining accuracies for the plurality of sparse monitoring datasets by comparing the reconstructed monitoring datasets to the baseline dataset, and selecting one or more survey geometries for arranging physical sources and physical receivers in a seismic survey based at least in part on the accuracies of the plurality of sparse monitoring datasets.
Systems, computer-readable media, and methods are provided. Blended baseline data is generated by numerically blending unblended baseline data according to a simultaneous shooting schedule scheme. Pseudo-deblended baseline seismic data is generated by applying a pseudo-deblending procedure to the blended baseline data. Machine learning labels are generated from common gathers of the pseudo-deblended baseline data and the unblended baseline data. A neural network is trained using the labels, the common gathers of the pseudo-deblended baseline data, and the unblended baseline data to produce common gathers of deblended baseline seismic data from the common gathers of the pseudo-deblended baseline seismic data.
A method for implementing enhanced oil recovery includes receiving a model of a subterranean volume of at least a portion of an oilfield and measurements collected for the subterranean volume, determining a model confidence index based at least in part on the model and the measurements, selecting one or more physical parameters for candidate pilot tests based at least in part on the model, the measurements, and the model confidence index, designing pilot tests for the individual candidate pilot tests based at least in part on one or more pilot test objectives, the model, and the model confidence index, selecting one or more pilot tests from among the designed pilot tests, and generating a pilot test implementation plan for the selected one or more pilot tests.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
E21B 43/16 - Enhanced recovery methods for obtaining hydrocarbons
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
A method for stockpiling sand and/or monitoring a sand stockpile includes obtaining one or more images associate with stockpiling sand used for a fracturing process of a hydrocarbon system and analyzing the one or more images to determine a site location for a sand stockpile and/or an amount of sand in the sand stockpile.
Citrate polyester additives for crude oils, mixtures of the citrate polyester additives and crude oils, and methods for producing or forming the mixtures are provided. The mixtures and methods comprise at least one citrate polyester additive introduce or applied to crude oil, wherein the at least one citrate polyester additive comprises one or more citrate crosspolymers.
C09K 8/524 - Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
C08G 63/06 - Polyesters derived from hydroxy carboxylic acids or from polycarboxylic acids and polyhydroxy compounds derived from hydroxy carboxylic acids
C08G 63/91 - Polymers modified by chemical after-treatment
C08L 67/04 - Polyesters derived from hydroxy carboxylic acids, e.g. lactones
C08L 101/00 - Compositions of unspecified macromolecular compounds
E21B 37/06 - Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting the deposition of paraffins or like substances
A perforation tool, and a bulkhead member for a perforation tool, are disclosed. The perforation tool has a loading tube, an initiator module, and a bulkhead member connected between the loading tube and the initiator module. The bulkhead member has a hollow body member with a central transverse plate having a central bore through the transverse plate along a longitudinal axis of the body member and an electrical conductor disposed in the central bore, the electrical conductor having a pin connection at a first end thereof and a box connection at a second end thereof.
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.
Methods of stimulating a hydrocarbon reservoir having carbonate components are described herein. An acid treatment material is developed by defining a diversion parameter as a ratio of volume of diversion material to be used for treatment of the reservoir to volume of fractures to be developed during acid treatment of the reservoir, defining a relationship between the diversion parameter and a diversion result, selecting a value of the diversion parameter based on the relationship, determining an amount of diversion material based on the selected value of the diversion parameter, and adding the amount of the diversion material to an acid treatment material. The reservoir is then subjected to acid treatment using the acid treatment material.
A method can include receiving a sonic data log for a length interval of a borehole in a geologic environment as acquired via a tool disposed in the borehole; representing the sonic data log using an ordered series representation with respect to length for at least a portion of the length interval; and inverting the sonic data log using the ordered series representation to generate a model of at least a portion of the geologic environment, where the model includes sonic velocity related property values.
E21B 47/14 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
G01V 1/28 - Processing seismic data, e.g. analysis, for interpretation, for correction
A method can include acquiring data during rig operations for a specified drillstring for drilling a specified borehole in a geologic environment, where the data include downhole survey data; determining a drillstring load based on at least a portion of the data; comparing the drillstring load to a plurality of modeled loads, where the plurality of modeled loads depend on the specified drillstring, the specified borehole, and at least a portion of the survey data and correspond to a plurality of different friction factor values; and, based on the comparing, estimating a friction factor value that corresponds to the drillstring load.
A choke gate valve includes a housing that defines a fluid bore and a gate that includes a throttling orifice. The gate is configured to move within the housing between a throttle position in which the gate extends across the fluid bore to position the throttling orifice in the fluid bore to throttle a fluid flow through the fluid bore and an open position in which the gate does not block the fluid bore to enable a full level of the fluid flow through the fluid bore. The choke gate valve may be used as part of a choke gate valve system to transition between first fracturing operations for a first well and second fracturing operations for a second well without shut off of a pump.
F16K 47/04 - Means in valves for absorbing fluid energy for decreasing pressure, the throttle being incorporated in the closure member
F16K 3/30 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing - Details
31.
INTEGRATING DOMAIN KNOWLEDGE WITH MACHINE LEARNING TO OPTIMIZE ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE
A method for monitoring operation or status of an electrical submersible pump (ESP) is provided, which includes a) collecting historical time-series data related to ESP operation; b) extracting historical time-series data related to healthy ESP operation from the historical time-series data of a); c) extracting feature data from the historical time-series data extracted in b); d) extracting or calculating values of at least one key performance indicator (KPI) related to healthy ESP operation from the historical times-series data extracted in b); e) using the feature data of c) and the values of at least one KPI of d) to train a machine learning (ML) model to predict at least one target KPI related to healthy ESP operation given feature data as input; and f) using the ML model trained in e) to monitor operation or status of the ESP. Other aspects are described and claimed.
An energy efficient and environmentally benign lithium recovery process is described. The process comprises extracting lithium from the brine source using a ion withdrawal process to form a lithium extract; providing electricity for the extracting using an energy source; and recovering thermal energy from the energy source for use in the extracting.
B01D 15/36 - Selective adsorption, e.g. chromatography characterised by the separation mechanism involving ionic interaction, e.g. ion-exchange, ion-pair, ion-suppression or ion-exclusion
C02F 9/00 - Multistage treatment of water, waste water or sewage
C22B 3/24 - Treatment or purification of solutions, e.g. obtained by leaching by physical processes, e.g. by filtration, by magnetic means by adsorption on solid substances, e.g. by extraction with solid resins
A method can include receiving input for a drilling operation that utilizes a bottom hole assembly and drilling fluid; generating a set of offset drilling operations using historical feature data, where the historical feature data are processed by computing feature distances; performing an assessment of the offset drilling operations as characterized by at least feature distance-based similarity between the drilling operation and the offset drilling operations; and outputting at least one recommendation for selection of one or more of a component of the bottom hole assembly and the drilling fluid based on the assessment.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/12 - 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 apparatus for use in a well bore is described herein. The apparatus includes a one-piece housing having a length in an axial direction from a first end to a second end, and end wall and a sidewall defining a cavity within the housing. The apparatus also includes a frame inside the cavity. The frame includes a charge receptacle, a detonator receptacle, a first electrical contact and a second electrical contact. The apparatus further includes a conductive material coupled with the first electrical contact.
Computing systems, computer-readable media, and methods for direct arrival replacement. The method includes creating intermediate data from an acquired data by attenuating a direct arrival signal or attenuating the direct arrival signal and one or more strong early arrival signals recorded at a receiver; transforming the temporary data from a first processing domain into a second processing domain; modelling the direct arrival signal in the second processing domain; estimating a scalar for model calibration and a seabed reflectivity from an area around the direct arrival signal; and inserting the direct arrival signal that is modelled into the intermediate data in the second processing domain.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
G01V 1/32 - Transforming one recording into another
An equipment controller can include a processor; memory accessible to the processor; and processor-executable instructions stored in the memory to instruct the equipment controller to: instantiate an edge application and an edge framework, where the edge framework includes a framework engine; receive sensor data; process the sensor data via the edge application to issue a call to the edge framework; responsive to the call, implement the framework engine to generate a result; and based at least in part on the result, issue an equipment control signal.
A method includes receiving a signal having a telemetry portion and a noise portion. The method may also include identifying one or more harmonic frequencies in the signal. The method may also include determining whether the one or more harmonic frequencies are in a predetermined frequency band. The method may also include determining whether a signal-to-noise ratio (SNR) of the signal is below a predetermined SNR threshold. The method may also include generating one or more notifications in response to the determination whether the one or more harmonic frequencies are in the predetermined frequency band and the determination whether the SNR is below the predetermined SNR threshold.
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 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
G01V 9/00 - Prospecting or detecting by methods not provided for in groups
A method, a non-transitory computer-readable medium, and a computing system are provided for determining a telemetry mode of a signal. A drilling telemetry signal is received from a downhole tool in a wellbore. A transformation is determined based at least partially upon the drilling telemetry signal. Multiple features are extracted based at least partially upon the transformation. A decision region is identified based at least partially upon the features. A telemetry parameter is identified based at least partially upon the decision region. A telemetry mode of the drilling telemetry signal is determined based at least partially upon the telemetry parameter. The drilling telemetry signal is decoded based at least partially upon the telemetry mode.
G01V 11/00 - Prospecting or detecting by methods combining techniques covered by two or more of main groups
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 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
G01V 9/00 - Prospecting or detecting by methods not provided for in groups
A method can include receiving sensor data; determining a rate of penetration drilling parameter value using a trained neural network and at least a portion of the sensor data; and issuing a control instruction for drilling a borehole using the determined rate of penetration drilling parameter value.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
41.
DEVICES, SYSTEMS, AND METHODS FOR HIGH FREQUENCY OSCILLATION MITIGATION
High frequency oscillation (HFO) comes in at least two types. Type 1 HFO is lower frequency and often associated with a motor. Type 2 HFO is higher frequency and often independent of a motor. To mitigate torsional strain due to Type 2 HFO, an HFO mitigation mechanism can be placed based on an oscillation node location to move the oscillation node to a new position which may be uphole of a tool or the BHA, or to a less vulnerable location. Mitigation can also include placing an energy damping component based on the oscillation node. This may be at a high displacement location distanced from the oscillation node, or may include placement at the oscillation node with an additional HFO mitigation mechanism to move the oscillation node away from the installation location. Oscillations may be damped by using any combination of flow restrictions, fluid bypasses, or axially compliant elements.
A surface well fracturing system having fluid conduits connected to surface fracturing equipment with quick connect systems is provided. In one embodiment, a fracturing system includes a frac pump, a frac supply manifold, and a fracturing fluid conduit connected to route fracturing fluid between the frac pump and the frac supply manifold. The fracturing fluid conduit is connected to the frac pump or to the frac supply manifold by a quick connect apparatus, which includes a segmented clamp having multiple clamp segments mounted on a shared support. Additional systems, devices, and methods are also disclosed.
A method includes obtaining a synthetic seismogram representing a seismic well tie, a shifted synthetic seismogram representing the seismic well tie, and a shift input including domain shift data for converting well log data from a depth domain to a time domain, generating a shift label based on the synthetic seismogram and the shifted synthetic seismogram using a machine learning model, determining that an accuracy of the shift label is less than a threshold based on a comparison of the shift input and the shift label, adjusting the machine learning model in response to determining that the accuracy of the shift label is less than the threshold, predicting a second shift for a second seismic well tie from a second seismogram using the machine learning model, and generating a seismic image based on the second seismic well tie, the second seismogram, and the second shift.
Environmentally acceptable branched alkyl alcohol ethoxylate accelerants for proppants coated with curable phenolic resin coating are described herein. Well treatment fluids described herein include an aqueous medium comprising a branched alkyl alcohol ethoxylate accelerant and a proppant having a curable phenolic resin coating dispersed in the aqueous medium.
Methods, computing systems, and computer-readable media are provided. A carbon footprint baseline is established for a drilling unit. Power consumption is calculated for drilling unit components. The power consumption of components is converted to CO2 emissions according to a GHG standard. The power consumption is transformed into real-time power consumption during drilling operations using power ratings, diversity factors, fuel usage, and specific fuel oil consumption. Real-time CO2 emissions are calculated based on the real-time power consumption. CO2 emissions calculations and modelling of supply transport units are performed based on previously collected power consumption data from supply transport units. The real-time CO2 emissions for the drilling operations are determined and presented.
G06Q 99/00 - Subject matter not provided for in other groups of this subclass
G06Q 10/0637 - Strategic management or analysis, e.g. setting a goal or target of an organisation; Planning actions based on goals; Analysis or evaluation of effectiveness of goals
A method for generating a drilling plan for drilling a wellbore at a field includes receiving data. The data includes one or more of geological properties at the field, wellbore properties, drilling tool parameters, rig characteristics of drilling rigs, and working practices of a plurality of drilling crews. The method also includes generating a plurality of candidate drilling plans for drilling the wellbore at the field. The method also includes estimating one or more outputs for the candidate drilling plans based at least partially upon the data. The one or more outputs include an amount of emissions generated to drill the wellbore using the candidate drilling plans. The method also includes presenting for selection one or more of the candidate drilling plans based at least partially upon the one or more outputs.
E21B 7/02 - Drilling rigs characterised by means for land transport, e.g. skid mounting or wheel mounting
G01V 3/18 - Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination or deviation specially adapted for well-logging
47.
DATA-DRIVEN SEPARATION OF UPGOING FREE-SURFACE MULTIPLES FOR SEISMIC IMAGING
A method includes receiving seismic data including signals collected using a receiver, the seismic data representing a subsurface volume, identifying a downgoing wavefield and an upgoing wavefield in the seismic data, identifying direct arrivals in the downgoing wavefield, estimating at least first-order multiple reflection signals in the upgoing wavefield based on the downgoing wavefield, the upgoing wavefield, and the direct arrivals, and generating seismic images representing the subsurface volume based at least in part on the at least first-order multiple reflection signals.
Systems and methods presented herein are configured to monitor gas storage in a well and, more specifically, to invert optical measurements to predict the fractional molar composition of an unknown composition of a gas mixture comprised of hydrogen, carbon dioxide, other gases, or combinations thereof, in any underground reservoir or salt dome where hydrogen, carbon dioxide, and/or the other gases are stored or exist.
E21B 47/10 - Locating fluid leaks, intrusions or movements
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 technique facilitates installation of a completion system having sequentially coupled base pipes and a corresponding alternate path system having alternate path shunt tubes. Sequential base pipes may be joined via a base pipe coupling. The alternate path shunt tubes disposed along sequential base pipes are then connected by jumper tubes. Additionally, the base pipe coupling and the jumper tubes are enclosed with a multi-section shroud by closing shroud sections over the base pipe coupling and the jumper tubes. A torque resistance system is employed to provide torsional rigidity along the shroud.
An inversion-based method has been developed to evaluate up to 5 or 6 nested casings by utilizing complementary sensitivities from time-domain collocated (relatively shallow) and multi-frequency, multi-spacing non-collocated (both relatively shallow and relatively deeper) pulsed eddy current measurements. Stand-alone inversion-based techniques are also disclosed to process time-domain collocated sensor measurements, which may come from single or multiple sensors of different lengths.
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 3/28 - 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 magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device using induction coils
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
G01V 3/38 - Processing data, e.g. for analysis, for interpretation or for correction
51.
THROUGH TUBING NEAR-FIELD SONIC MEASUREMENTS TO MAP OUTER CASING ANNULAR CONTENT HETEROGENEITIES
Aspects described herein provide for methods and apparatus for characterizing azimuthal heterogeneities in a barrier installed outside an outer casing in a borehole traversing a formation in a cased hole configuration including an inner and outer casing. The approach is based on specific attributes in sonic signals acquired with an azimuthal and axial array receiver system located inside the inner casing. The methods include slowness-time-coherence (STC) processing based on specific arrivals identified in data acquired by axial arrays associated with multiple azimuthal sections of the receiver system. The specific arrivals contain STC signatures that can be examined in terms of coherence amplitude and localization within STC maps. Based on specific attributes in the sonic signals, an azimuthal coverage of the outer casing annular contents can be created.
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
A method for configuring telemetry transmission includes receiving a transmitted telemetry signal at the earth's surface. The received signal is selected and processed to compute a measured power spectral density (PSD). A theoretical PSD is computed of the transmitted signal at the known carrier frequency and processed in combination with the measured PSD to compute an attenuation factor of the transmitted signal at a plurality of frequencies .
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
H04B 17/309 - Measuring or estimating channel quality parameters
Automated systems and methods are provided for continuous monitoring of the flaring of waste gas at an industrial facility, which employ an RGB camera operably coupled to a gateway device by a data communication interface. The RGB camera is configured to capture time-series color image frames of a flare and communicate the time-series color image frames to the gateway device. The gateway device includes an image processing module and a flare optimization module executing on the gateway device. The image processing module is configured to process the time-series color image frames to determine at least one flare parameter that provides a qualitative measurement of the combustion efficiency of the flare over time. The flare optimization module is configured to adjust relative amount of waste gas to at least one assist gas for the flare based on the at least one flare parameter to continuously optimize the combustion efficiency of the flare.
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
F23N 5/08 - Systems for controlling combustion using devices responsive to thermal changes or to thermal expansion of a medium using light-sensitive elements
Rotor bearings are provided. The motor bearing can be used in an electric submersible pump motor. The bearing can include a body and one or more anti-rotation pins disposed partially in a groove in an outer surface of the body and configured to be received in a corresponding keyway in an inner diameter of a stator. The anti-rotation pin prevents or inhibits rotation of the bearing relative to the stator.
E21B 17/046 - Couplings; Joints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
55.
WELLBORE DATA DEPTH MATCHING USING CHANGE POINT ALGORITHMS
A method includes receiving a well log having a signal. The method also includes identifying in the signal a first change point that demarcates a first signal region and a second signal region. The method also includes determining that the first signal region is inconsistent in comparison to the second signal region. The method also includes producing a modified well log by removing the first signal region from the signal in response to determining that the first signal region is inconsistent in comparison to the second signal region.
G01V 3/18 - Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination or deviation specially adapted for well-logging
A method can include receiving real-time, time series data from equipment at a wellsite that includes a wellbore in contact with a fluid reservoir; processing the time series data as input to a trained machine learning model to predict a future solids event related to influx of solids into the wellbore from the fluid reservoir; and outputting a time of the future solids event.
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 fracturing system having rams for controlling flow through a fracturing tree is provided. In one embodiment, a well intervention method includes injecting fracturing fluid into a well through a bore of a frac stack coupled to a wellhead. The frac stack includes rams that can be moved between open and closed positions to control flow through the bore. The well intervention method also includes coupling a lubricator to the frac stack without a blowout preventer between the lubricator and the frac stack and lowering an intervention tool from the lubricator through the bore of the frac stack and into the well. Additional systems, devices, and methods for fracturing and intervention are also disclosed.
A method for modeling a subsurface property for a subterranean volume of interest includes receiving input measurement data representing a subterranean volume of interest, predicting a subsurface property based at least in part on the input measurement data using a first machine learning model, predicting a subsurface property model based at least in part on the subsurface property, the input measurement data, or both, using a second machine learning model, predicting synthetic measurement data based at least in part on the subsurface property model using a third machine learning model, a physics-based model, or both, comparing the synthetic measurement data and the input measurement data, and training the first machine learning model, the second machine learning model, or both based at least in part on the comparing.
A method can include receiving inputs for a well; generating scenarios for the well using the inputs; instructing a simulator to simulate generated scenarios; receiving simulation results for at least some of the generated scenarios; and assessing the received simulation results for implementation of one or more well actions for the well.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 47/26 - Storing data down-hole, e.g. in a memory or on a record carrier
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
60.
AUTOMATIC SALT GEOMETRY DETECTION IN A SUBSURFACE VOLUME
A method includes receiving seismic data and an initial velocity model, generating a first seismic image based at least in part on the seismic data and the initial velocity model, training a machine learning model to predict salt masks based at least in part on seismic images, merging the initial velocity model and the first salt mask to generate a first modified velocity model, generating an updated velocity model based at least in part on the first modified velocity model, generating a second seismic image based at least in part on the updated velocity model, predicting a second salt mask based at least in part on the second seismic image and the updated velocity model, using the trained machine learning model, and merging the updated velocity model and the second salt mask to generate a second modified velocity model.
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
Methods and systems are provided for monitoring the operation of a valve, which employ a data acquisition unit and a gateway device located at an industrial site where the valve is being used, and at least one cloud-computing system located remotely from the industrial site. At least one sensor is mounted on the valve at the industrial site. The data acquisition unit includes an interface to the at least one sensor. The gateway device includes a first interface to the data acquisition unit and a second interface to the cloud computing system. The data acquisition unit is configured to receive at least one sensor signal supplied by the at least one sensor and processes the at least one sensor signal to extract time-series sensor data for supply to a gateway device. The gateway device is configured to forward the time-series sensor data supplied by the data acquisition unit to the cloud computing system. The cloud computing system is configured to receive, store, and process the time-series sensor data communicated from the gateway device for remote monitoring of operation of the valve at the industrial site.
F16K 37/00 - Special means in or on valves or other cut-off apparatus for indicating or recording operation thereof, or for enabling an alarm to be given
H04L 12/66 - Arrangements for connecting between networks having differing types of switching systems, e.g. gateways
62.
SYSTEMS AND METHODS FOR DELIVERING DEGRADABLE POLYESTER DURING GRAVEL PACKING
Systems and methods deliver degradable polyester during gravel packing and may include a gravel pack system disposed within a wellbore formed in a subterranean formation. The systems and methods may include drilling at least one interval of a wellbore with a non-aqueous wellbore fluid, wherein the non-aqueous wellbore fluid produces a filter cake in the at least one interval of the wellbore and gravel packing an interval of a wellbore traversing a subterranean formation with a gravel pack that comprises non-aqueous gravel pack carrier fluid and proppants. The systems and methods may also include hydrolyzing degradable polyester that is associated with the gravel pack and degrading at least one portion of the filter cake.
Methods and systems are provided for monitoring a physical asset, which includes receiving or collecting time-series data related to operation or status of the physical asset; identifying a time period when the physical asset is experiencing a change in operational state; extracting time-series data corresponding to the time period as event data; generating label data that classifies or characterizes the event data as pertaining to a particular type of event; saving the event data and the corresponding label data in a data repository; and using the event data and label data stored in the data repository to train or update a machine learning system to detect the occurrence of events that are similar to the event types of the labeled event data stored in the data repository from time-series data generated by the physical asset or by another physical asset that operates in a similar manner to the physical asset.
A charge canister for a perforation tool has a cylindrical body with an expansion portion extending along a radius of the cylindrical body, the expansion portion having a narrow portion at a first end of the expansion portion and a wide portion at a second end of the expansion portion opposite from the first end. An explosive material is disposed within the expansion portion in direct contact with an interior surface thereof.
A method can include receiving data for a bottom hole assembly of a drillstring and a drill plan; generating candidate trajectories using at least a portion of the data; generating drill command schedules for the candidate trajectories; ranking the candidate trajectories based at least in part on the drill command schedules; and outputting at least a top ranked candidate trajectory and its corresponding drill command schedule.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/12 - 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 technique for monitoring valve and pump efficiencies for positive displacement pumps. The techniques include utilizing a data acquisition system to attain intake and discharge pressure data in combination with real-time encoder position data. Thus, when combined, output from a pump may be monitored in real-time. As a result, pump life may be extended beyond an anticipated changeout schedule. By the same token, premature pump inefficiencies may also be detected for taking a pump offline in advance of expected life. In either circumstance, multi-pump operations may be substantially enhanced with cost and time savings realized.
Gas monitoring systems (500) and methods for determining a burning hydrocarbon effluent gas plume property. A laser emission system emits laser beams (564) along a path through the plume (532). A detection system facilitates determining intensity data indicative of intensities of the laser beams (564) backscattered by a surface (522) after passing through the plume (532). The laser emission system emits a first laser beam (564) along the path while tuning its wavelength around a wavelength corresponding to a CO2 spectral absorption line. The laser emission system emits a second laser beam (564) along the path while tuning its wavelength around a wavelength corresponding to a spectral absorption line of a second predetermined gas. The processing system determines a first concentration path length of the CO2 based on the first intensity data, a second concentration path length of the second predetermined gas based on the second intensity data, and the plume property based on the determined concentration path lengths. The plume property may be the rate of emission of the second predetermined gas or the combustion efficiency.
G01N 21/31 - Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry
G01N 21/39 - Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry using tunable lasers
G01N 21/3504 - Investigating relative effect of material at wavelengths characteristic of specific elements or molecules, e.g. atomic absorption spectrometry using infrared light for analysing gases, e.g. multi-gas analysis
A gyroscope assembly is maintained in a park position during drilling activities. In the park position, a sensitive axis of a gyroscope in the gyroscope assembly is perpendicular or approximately perpendicular to a longitudinal axis of a downhole tool. Maintaining the park position during drilling activities reduces the drift bias caused by overloading the input signal of the gyroscope due to rotation of the downhole tool.
E21B 47/013 - Devices specially adapted for supporting measuring instruments on drill bits
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
Electric submersible pump systems, and more particularly, seals for ESPs, are provided. An electric submersible pump includes a plurality of impellers; a plurality of diffusers; at least one sealing ring positioned axially between two consecutive diffusers of the plurality of diffusers; and at least one O-ring positioned axially between the at least one sealing ring and a lower of the two consecutive diffusers.
A hanger system for use with a housing of a wellhead includes a hanger assembly. The hanger assembly includes a hanger having a respective radially- outer surface and a radially-extending surface, as well as a first annular wedge having a respective radially-outer surface with a first annular wedge surface texture. The radially-extending surface is configured to engage a shoulder of the housing of the wellhead while the hanger assembly is in a landed position within the housing of the wellhead, and the first annular wedge surface texture is configured to engage a respective-radially inner surface of the housing of the wellhead while the hanger assembly is in a sealed position within the housing of the wellhead.
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.
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 1/32 - Transforming one recording into another
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
A tubing pressure insensitive and hydrostatic pressure insensitive control system includes a housing, a hydraulic piston sealingly disposed in the housing via a first seal set, and a balance piston sealingly disposed in the housing via, at least, a second seal set and a third seal set, the balance piston comprising a through-piston communication port. The housing includes a control pressure chamber associated with the hydraulic piston, and a balance pressure chamber associated with the balance piston. The system also includes a control line from the housing to surface, the control line being in fluid communication with the control pressure chamber, and a balance line from the housing to the surface, the balance line being in fluid communication with the balance pressure chamber.
A MEG recovery process is described, in which a MEG stream is processed by performing a divalent treatment to reduce dissolved divalent cations in the portion of the stream; performing a sulfate treatment to reduce dissolved sulfate ions in the stream, the sulfate treatment comprising adding an underdose of one or more calcium halides, one or more lower calcium carboxylates, or a mixture thereof to a treatment stream; and precipitating calcium sulfate from the treatment stream; performing a solids removal treatment to reduce solids in the stream; and returning the treated stream, depleted in divalent cations, sulfate ions, and solids, to the MEG recovery process.
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.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
A method and a processing device are provided for predicting standpipe pressure. A Bayesian linear regressor is initialized. Priors for the Bayesian linear regressor are initialized based on previous drilling operations that used a same bottom hole assembly. Measurement data associated with drilling a well is received in real time. An online Bayesian linear regressor update is generated using QR decomposition for a model. Responsive to determining that at least some coefficients violate physical rules, the at least some of the coefficients are set to a respective default value that is either zero or a positive value. Coefficients and uncertainty are updated based on at least one of the online Bayesian linear regressor update and the setting of at least some of the coefficients. The model is then visualized. Visualization helps a user identify whether the learned model makes sense.
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
78.
SYSTEM AND METHOD FOR NAVIGATING GEOLOGICAL VISUALIZATIONS
A method, computing system, and computer-readable medium for navigating a geologic environment, in which the method includes obtaining first geological data representing a first location, correlating the first geological data with a chronostratigraphic timeline, receiving a selection of a second location, correlating second geological data representing the second location with the chronostratigraphic timeline, determining one or more characteristics of a geology of the second location based at least in part on the first geological data from the first location using the chronostratigraphic timeline, and visualizing a stratigraphic navigator representing the chronostratigraphic timeline and at least some of the second geological data for the second location.
A 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.
An actuator assembly includes a threaded shaft, a threaded nut that is threadably coupled to the threaded shaft, an annular ratchet positioned about the threaded shaft and comprising one or more tracks, and a pin that extends from the threaded shaft and into the one or more tracks. The threaded nut may include a first circumferentially-facing surface, the annular ratchet may include a second circumferentially-facing surface, and the first and second circumferentially- facing surfaces are configured to contact one another to enable the threaded nut to block rotation of the annular ratchet with the threaded shaft. The actuator assembly may enable the threaded nut to move to a limit position and hold full motor torque, but also to break free from the limit position with relatively low torque (e.g., less than the full motor torque; as compared to actuator systems that are devoid of certain features of the actuator assembly).
Methods, computing systems, and computer-readable media for dynamically adjusting drilling parameters during a drilling operation. The approach involves receiving, in real time, drilling parameter measurements and response measurements during a drilling operation. If the response measurements are below the lower limit of a window or trending downwards, the approach determines a new drilling parameter value that will increase the response measurement. The approach dynamically adjusts the drilling parameter value above the sectional limit, while still respecting hard limits. When the measured value improves, the approach returns the limit for the drilling parameter to the sectional limit.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/008 - Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
The position of a droppable object (e.g., a cementing plug or drillpipe dart) in a cased wellbore may be determined in real time during a cementing operation. A pressure data acquisition system is installed at a wellsite, a pressure transducer is installed at the wellhead and a flowmeter is placed to measure fluid displacement rate. The fluid displacement causes the droppable object to travel through the casing towards a target position. During displacement the pressure data and flow-rate data are transmitted to a pressure data acquisition system and a flowmeter, respectfully. The pressure and flow-rate data are processed mathematically to obtain pressure pulses, pulse reflections or both. The fluid flow rate data and pressure data are processed by generating a pressure spectrogram converted to pulses. The pulses are then matched with casing tally pulses, thus allowing correction of the droppable object depth.
The present disclosure relates to systems, methods, and non-transitory computer-readable media for dynamically utilizing, in potentially real time, anomaly pattern detection to optimize operational processes relating to well construction or subterranean drilling. For example, the disclosed systems use time-series data combined with rig states to automatically detect and split similar operations. Subsequently, the disclosed systems identify operation anomalies from a field-data collection utilizing an automated anomaly detection workflow. The automated anomaly detection workflow can identify operation anomalies at a more granular level by determining which process behavior contributes to the operation anomaly (e.g., according to corresponding process probabilities for a given operation). In addition, the disclosed systems can present graphical representations of operation anomalies, process behaviors (procedural curves), and/or corresponding process probabilities in an intuitive, user-friendly manner.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/26 - Storing data down-hole, e.g. in a memory or on a record carrier
?Methods for locating fluid interfaces in a cased wellbore include generating vibrations in the casing, thereby forming oscillations in the wellbore fluids and the casing. The oscillations are detected by a vibration detector. The oscillations are recorded by a data acquisition system. Mathematical processing of the oscillations by cepstrum analysis is performed to determine the depths of interfaces between fluids in the annulus. The methods may also be employed to determine the time at which a cement slurry begins to set and harden. The methods may be performed in real time.
A method can include receiving real time data where the real time data include at least pressure sensor data from multiple pressure sensors of a hydrocarbon fluid production network for multiple locations in the hydrocarbon fluid production network; generating an expected operational region in a multidimensional domain using at least a portion of the real time data; operating a leak detection system using the expected operational region; tracking at least a portion of the real time data in the multidimensional domain; and issuing a leak detection signal responsive to the tracking indicating an excursion from the expected operational region, where the leak detection signal indicates the presence of a leak in the hydrocarbon fluid production network.
A method can include receiving real-time data during a drilling operation performed by a drillstring that includes a mud motor and a bit characterized by an expected performance profile; determining actual performance of the drillstring based at least in part on the real-time data; predicting degraded performance of the drillstring based at least in part on the real-time data and a mud motor degradation model; and updating the expected performance profile based on a comparison of the actual performance and the degraded performance.
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
87.
SLIDE DRILLING CONTROL BASED ON TOP DRIVE TORQUE AND ROTATIONAL DISTANCE
Apparatus and methods for controlling slide drilling based on torque and rotational distance of a top drive connected with an upper end of a drill string. A method may comprise operating a processing device that receives torque measurements indicative of torque output by the top drive, receives rotational distance measurements indicative of rotational distance imparted by the top drive, causes the top drive to rotate the drill string while the drill string is off-bottom, determines a reference torque based on the torque measurements received while the drill string is rotated off-bottom, causes the top drive to alternatingly rotate the drill string based on the reference torque to perform slide drilling, determines a reference rotational distance based on the rotational distance measurements received during the slide drilling, and causes the top drive to alternatingly rotate the drill string based on the reference rotational distance to perform the slide drilling.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
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, during drilling operations at a wellsite, receiving operational data, where the data include hookload data, surface rotation data and block position data; training a controller using the hookload data, the surface rotation data and the block position data for determination of one or more transition thresholds, where the transitions thresholds include an in-slips to out-of-slips transition threshold and an out-of-slips to in-slips transition threshold; during the drilling operations, receiving additional operational data that include additional hookload data; and storing at least a portion of the additional operational data in association with slips state as determined based at least in part on a comparison of at least a portion of the additional hookload data and at least one of the determined transition thresholds.
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
89.
SYSTEM AND METHOD FOR DETERMINING WELL CORRELATION
A method includes determining a search window in a target well. The method also includes identifying one or more reference wells based at least partially upon a location of the target well. The method also includes predicting a plurality of locations of a target well marker in the target well based at least partially upon the one or more reference wells. The locations of the target well marker are within the search window. The method also includes determining similarity values for the locations of the target well marker. The method also includes assigning the target well marker to at least one of the locations based at least partially upon the similarity values.
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
Cement slurries are prepared that comprise water, a hydraulic cement and particles of an oil-absorbent material. The particles are present in an amount sufficient to alter a property of a non-aqueous drilling fluid. The cement slurry is placed in a subterranean well, whereupon the slurry contacts residual drilling fluid on casing and formation surfaces. The oil-absorbent material in the cement slurry may reduce the mobility of the drilling fluid, thereby improving zonal isolation. The oil-absorbent material may be a polyolefin block copolymer.
C09K 8/508 - Compositions based on water or polar solvents containing organic compounds macromolecular compounds
C04B 24/26 - Macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
C04B 28/02 - Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
C09K 8/467 - 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 containing additives for specific purposes
A method, computer system, and non-transitory computer-readable medium are provided. An energy domain data object is retrieved from a database. The energy domain data object was created using an energy domain software application based on collected energy data. The energy domain data object is embedded in a presentation file and is visualized by executing a presentation application using the presentation file. One or more parameters of the energy domain data object from the presentation file are adjusted. At a second point in time, an updated copy of the energy domain data object from the database is retrieved using the presentation file. A visualization of the energy domain data object is modified based on the updated copy of the domain data object.
Embodiments described herein provide a downhole tool (e.g., a retrievable bridge plug) that includes a sealing device and a load retention/equalization mechanism. The sealing device includes an elastomer seal component and an expansion device configured to radially expand outwardly to compress the elastomer seal component against a wellbore casing within which the downhole tool is located. The sealing device further includes lower and upper support barriersconfigured to radially expand outwardly against the wellbore. The sealing device also includes a seal energizing spring configured to maintain an initial setting force of the elastomer seal component against the wellbore casing. The load retention/equalization mechanism includes a spool/inflation valve configured to direct fluid into an internal volume to inflate the elastomer seal component radially outwardly based on a differential pressure between a first volume uphole relative to the downhole tool and a second volume downhole relative to the downhole tool.
A method for drilling a well includes generating a plurality of proposed drilling actions using a plurality of working agents based on a working environment, simulating drilling responses to the proposed drilling actions using a plurality of validation agents in a validation environment that initially represents the working environment, determining rewards for the proposed drilling actions based on the simulating, using the validation agents, selecting one of the proposed drilling actions, and causing a drilling rig to execute the selected one of the proposed actions.
A perforation tool features a container with a longitudinal axis; an initiator module in the container, the initiator module having a firing circuit, an electrical contact at the longitudinal axis, and a detonator housing; and a shaped charge frame in the container, the shaped charge frame having a first end; a second end opposite the first end; a recess for accepting a shaped charge between the first end and the second end, the recess having a wide end and a narrow end, wherein the longitudinal axis is between the wide end and the narrow end; a first electrical contact at the first end, the first electrical contact located at the longitudinal axis; a second electrical contact at the second end, the second electrical contact located at the longitudinal axis; an electrical conductor connecting the first and second contacts; and a ballistic pathway coupling the detonator housing to the narrow end of the recess.
Shaped charge tools for perforating hydrocarbon wells are described herein. A shaped charge frame assembly described herein comprises a tubular electrical conductor and a shaped charge frame disposed around the tubular electrical conductor and rotatably engaged with the tubular electrical conductor. One or more bearings may be used to engage the shaped charge frame with the tubular electrical conductor, or the engagement may be bearing-free.
A system for use in a well includes a liner hanger including a mandrel, a cone mounted about the mandrel, the cone having tapered slips, a plurality of tapered slips slidably received in the tapered slots, each tapered slip of the plurality of tapered slips comprising a plurality of teeth, wherein each tapered slip of the plurality of tapered slips and the corresponding tapered slot includes a setting ramp, and a loading ramp separate from the setting ramp, and an actuator mounted about the mandrel to selectively shift the plurality of tapered slips between a radially contracted position and a radially expanded, set position.
A method can include receiving a location from a process guided by an agent, where the process intends to reach a target; assigning uncertainty to the process; performing multiple simulation runs, guided by agent output, from the location with an intent to reach the target, where the multiple simulation runs account for the uncertainty; and generating output based on the multiple runs that characterizes an ability of the agent to reach the target in view of the uncertainty.
E21B 41/00 - Equipment or details not covered by groups
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
98.
WELL CONSTRUCTION WORKFLOW SELECTION AND EXECUTION
A method for conducting wellsite activities includes receiving measured sensor data collected by one or more sensors in a wellsite construction rig, determining a data quality of the measured sensor data based on a plurality of data quality dimensions, predicting predicted sensor data using a model, comparing the measured sensor data with the predicted sensor data, determining an uncertainty of the measured sensor data based at least in part on the data quality and the comparison, and selecting one or more workflows for implementation using the one or more sensors, the wellsite construction rig, or both.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 47/26 - Storing data down-hole, e.g. in a memory or on a record carrier
A method can include, for a control action for a hydraulic fracturing operation of a well, using a trained machine learning model that predicts treatment pressure of the hydraulic fracturing operation, determining if the control action increases efficiency; if the control action increases efficiency, assessing viability of the control action with respect to one or more predefined criteria; and, if the control action is viable, issuing the control action for implementation during the hydraulic fracturing operation.
A fingerboard includes a first finger and a second finger that are laterally offset from one another. A slot is defined between the first and second fingers. The fingerboard also includes a latch coupled to the first finger and configured to actuate from an open latch position into a closed latch position, and a panel coupled to the first finger and configured to actuate from an open panel position into a closed panel position. A tubular member in the slot prevents the panel from actuating into the closed panel position. The latch in the open latch position prevents the panel from actuating into the closed panel position. The panel in the closed panel position extends laterally between the first finger and the second finger so as to provide a surface across the slot.
patents
