Abstract: A method for history matching a reservoir model based on actual production data from the reservoir over time generates an ensemble of reservoir models using geological data representing petrophysical properties of a subterranean reservoir. Production data corresponding to a particular time instance is acquired from the subterranean reservoir. Normal score transformation is performed on the ensemble and on the acquired production data to transform respective original distributions into normal distributions. The generated ensemble is updated based on the transformed acquired production data using an ensemble Kalman filter (EnKF). The updated generated ensemble and the transformed acquired production data are transformed back to respective original distributions. Future reservoir behavior is predicted based on the updated ensemble.

Abstract: Disclosed are methods, systems, and computer-readable medium to perform operations including: generating, based on production data for a wellbore, (i) a water-oil-ratio with respect to time (WOR) dataset for the wellbore, (ii) a time-derivative dataset (WOR?) of the WOR dataset; generating a WOR log-log plot of the WOR dataset and a WOR? log-log plot of the WOR? dataset; identifying at least one trend in the WOR log-log plot and the WOR? log-log plot; determining, based on the at least one identified trend, a first type of water breakthrough; generating, based on pressure data from a build-up pressure test in the wellbore, a log-log plot of time-derivative pressure data with respect to time (P?); determining, based on the P? log-log plot, a second type of water breakthrough; correlating the first and second type of water breakthrough; and determining, based on the correlation, whether to perform a water treatment for the wellbore.

Abstract: The present disclosure relates to a method and system for evaluating the macro resilience of offshore oil well control equipment. The method for evaluating the macro resilience of offshore oil well control equipment comprises six steps: determining the type and strength of external disaster; calculating the failure rate of components; calculating the recovery rate of the components; modeling the BN for a degradation process; modeling the BN for a maintenance process; and calculating the resilience of the offshore oil well control equipment. A system for evaluating the macro resilience of offshore oil well control equipment comprises an external disaster evaluation module, a component failure rate calculation subsystem, a reliability degradation process simulation module, a fault identification module, a component recovery rate calculation module, a reliability recovery process simulation module, a reliability change curve derivation unit and an resilience calculation unit.

Abstract: Various computer-implemented methods for utilizing a modified upper confidence bound (UCB) in an agent-simulator environment in well placement planning for oil fields are disclosed herein. A set of well placement sequences for placing well in a geographical region may be received, where each well placement sequent defines a sequence of multiple oil wells to be placed within the geographical region. A computer-implemented simulation may be executed on each of the well placement sequences to determine, for each of the well placement sequences, a reward based upon a calculated hydrocarbon recovery and a cost of the calculated hydrocarbon recovery. The well placement sequences may be iteratively selected for the computer-implemented simulations using the modified UCB algorithm and based upon the rewards determined for each of the plurality of well placement sequences.

Abstract: A method can include receiving realizations of a model of a reservoir that includes at least one well where the realizations represent uncertainty in a multidimensional space; selecting a portion of the realizations in a reduced dimensional space to preserve an amount of the uncertainty; optimizing an objective function based at least in part on the selected portion of the realizations; outputting parameter values for the optimized objective function; and generating at least a portion of a field operations plan based at least in part on at least a portion of the parameter values.

Abstract: A method may include obtaining a selection of various user-defined coarsening parameters. The user-defined coarsening parameters may include a predetermined fine-grid region in a geological region of interest and a predetermined cell distance. The method may further include determining an area of interest (AOI) mask for the geological region of interest based on the predetermined fine-grid region. The method may further include determining a geological property mask based on the user-defined coarsening parameters. The geological property mask may correspond to a predetermined geological feature within the predetermined cell distance from the AOI mask. The method may further include generating a coarsened grid model using grid model data and well data for the geological region of interest. The method may further include performing a reservoir simulation of the geological region of interest using the coarsened grid model.

Abstract: A method includes receiving first data and building a first model of a well based at least partially upon the first data. The method also includes receiving second data and building a second model including a network of flowlines based at least partially upon the second data. At least one of the flowlines is connected to the well. The method also includes combining the first model and the second model to produce a combined model. The method also includes calibrating the combined model to produce a calibrated model. Calibrating the combined model includes receiving measured data, miming a simulation of the combined model to produce simulated results, and adjusting a calibration parameter to cause the simulated results to match the measured data. The calibration parameter includes a productivity index of a fluid flowing out of the well. The method also includes updating the calibrated model to produce an updated model.

Abstract: Embodiments of the present disclosure relate to a method of exploiting underground resources with a negative thixotropic fluid, which induces the fault or the fracture to slip by replacing a conventional mode of injecting water with a mode of injecting the negative thixotropic fluid. According to the negative thixotropy of the injected fluid, when the fault or the fracture does not slip, viscosity of the negative thixotropic fluid is low, and the negative thixotropic fluid could flow in the fracture network. When the fault or the fracture slips, a great shear strain rate is generated, such that the viscosity of the negative thixotropic fluid is rapidly increased with the shear strain rate, to generate a great resistance force, thereby preventing the fault from further slipping.

Abstract: A comprehensive three-dimensional exploitation experimental system for large-scale and full-sized exploitation wells includes a reactor, configured to prepare a natural gas hydrate sample, for simulating an environment for forming a natural gas hydrate reservoir in seafloor sediments. The reactor includes a reactor body, an upper cover disposed at an upper surface of the reactor body, and a lower cover disposed at a lower surface of the reactor body; a gas introducing module, configured to introduce gas to the reactor during hydrate formation; a liquid introducing module, configured to introduce liquid to the reactor during hydrate formation; a temperature regulating module, configured to regulate a temperature in the reactor; a data collecting-processing-displaying module, configured to collect, store, process and display data of the comprehensive three-dimensional exploitation experimental system during an experiment.

Abstract: A method may include obtaining a real-time petrophysical data derived from a plurality of well logs during drilling and utilizing the real-time petrophysical data to quantify a formation damage profile using a resistivity tornado chart and a wellbore modeling. The method further includes utilizing the resistivity tornado chart to determine a depth of invasion inside a formation at each depth in a wellbore by using ratios between different resistivity logs obtained while drilling and creating a synthetic wellbore model by using a fluid flow equation for the wellbore modeling and calculating a time-specific invasion profile to determine a condition at a flowback time. The method further includes performing a computational fluid dynamics investigation in order to identify invaded fluid flow characteristics from the formation to the wellbore and calculating a duration needed to flowback an obtained invaded volume for removal of the formation damage based on a fluid flow behavior.

Abstract: Computer-implemented stratigraphic play quality generation is disclosed. Stratigraphic data can be processed from each of a plurality of respective data sources to generate conditioned stratigraphic data. From at least some of the conditioned stratigraphic data, attributes of at least one seismic sequence can be extracted, and at least one seismic surface and at least one structural element associated with at least some of the conditioned stratigraphic data can be determined. At least some of the conditioned stratigraphic data representing sedimentary layers can be correlated with seismic reflection data to ascertain a subsurface of the geologic area at a respective depth. Reservoir properties associated with the geologic area are linked to elastic properties, and a 2D model built. Moreover, 3D map can be generated that is usable for a prospective drilling plan.

Abstract: A method of increasing hydrocarbon recovery from a wellbore in a tight formation with greater breakdown pressures, the method including using hydro-jetting to effect a plurality of oriented cavities or discoidal grooves in the horizontal portion of the wellbore to overcome near-wellbore stresses, injecting a thermally controlled fluid into the wellbore to alter the temperature of the formation and lower stresses, and then fracturing the formation to generate a series of fractures that can be formed in a planar formation.

Abstract: Systems and methods for evaluating simulation models are disclosed. In one embodiment, a method of evaluating a simulation model of a hydrocarbon field includes merging simulated reservoir data and actual reservoir data to generate merged reservoir data, and cross-linking the merged reservoir data with three-dimensional model data. The method further includes calculating one or more surface metrics from at least one of the merged reservoir data and the three-dimensional model data, calculating one or more subsurface metrics from at least one of the merged reservoir data and the three-dimensional model data, and calculating one or more overall history match indicators, one or more surface history match indicators, and one or more subsurface history match indicators from the one or more surface metrics, the one or more subsurface metrics, and the three-dimensional model data.

Abstract: A system is described for estimating well production and injection rates of a subterranean reservoir using machine learning models. The system may include a processor and a non-transitory computer-readable medium comprising instructions that are executable by the processor to cause the processor to perform various operations. The processor may receive a set of static geological data about at least one subterranean reservoir in a subterranean formation. The processor may apply a trained convolutional neural network to the set of static geological data and data on initial states of dynamic reservoir properties to determine dynamic outputs of the subterranean reservoir. The processor may determine well data by extracting the set of static geological data and the dynamic outputs at well trajectories. And, the processor may apply a trained artificial neural network to the well data and subterranean grid information about the subterranean reservoir to generate estimated well production and injection rates.

Abstract: Disclosed are methods, systems, and computer-readable medium to perform operations including: receiving, by a computing device, parameters of the fractured well, wherein the fractured well comprises a wellbore and one or more hydraulic fractures extending from the wellbore; generating, by the computing device and based on the parameters of the fractured well, an equivalent complex well that represents the fractured well; and executing, by the computing device and using the equivalent complex well, a simulation that simulates the performance of the fractured well.

Abstract: A computerized method for management of a slurry injection well and the associated surface facility. The method utilizes real time and historical data of injection and slurry parameters in conjunction with computer simulations on a computer-modelled reservoir to predict well behavior during one or a series of injection events. The system determines optimized injection operation schedules, recommends and implements changes to an injection operation, including while in process such as through automated equipment control.

Abstract: A method for recording data relating to the performance of an oil and gas flow network uses statistical data to represent raw data in a compact form. Categories are assigned to time intervals in the data.

Abstract: The present disclosure provides a multi-scale three-dimensional (3D) engineering geological model construction system and method. A regional geological model of a target region, a site geological model of each engineering site, and a drilling geological model of each drilling well are constructed. The geological model of each drilling well is superimposed to the site geological model of the corresponding engineering site in the way of step-by-step superimposition, and the site geological model of each engineering site fused with the drilling geological model is superimposed to the regional geological model of the target region. Thus, multi-scale geological model fusion of drilling well, engineering site, and regional mountain is realized.

Abstract: Disclosed herein are self-aware, self-modifying, autonomous connection mechanisms. Exemplifying intelligent systems introduce some of the embodiments of the autonomous connection mechanism techniques.

Abstract: The present disclosure discloses a method for calculating a safe drilling fluid density in a fractured formation, including the following steps: S1, performing image processing to identify a downhole fracture; S2, establishing three-dimensional (3D) geological models based on parameters of the downhole fracture, and establishing a drilling wellbore model based on a size and length of a wellbore; S3, assigning the model with material parameters, boundary conditions, and upper and lower bounds of an initial drilling fluid density, and calculating accuracy; S4, solving the 3D geological models using a 3-dimension distinct element code (3DEC) and determining stability of a well wall; S5, determining upper and lower bounds of a drilling fluid density using dichotomy; S6, repeating steps S4 to S5; and S7, after set accuracy conditions are reached, saving and outputting the safe drilling fluid density.

Abstract: A computer receives a measured wetness of and a measured ?2H value associated with a test gas sample from a hydrocarbon formation. The measured wetness is a molar ratio of heavy gas compounds over a total gas within the measured sample. The computer receives calculated wetnesses calculated ?2H values associated with a gas samples taken from one or more analogous hydrocarbon reservoirs. The measured wetness received for the test gas sample is identified from among the plurality of calculated wetnesses. The computer determines a corresponding ?2H value from among the calculated ?2H values that corresponds to the measured wetness of the test gas sample. The computer determines a predicted sample VRo (vitrinite reflectance equivalent) for the test gas sample based on the corresponding ?2H value and a correlation of ?2H values to VRo values. Hydrocarbons are produced from the hydrocarbon formation based on the predicted sample VRo.

Abstract: The present invention relates to a system and method for modelling flow conditions in a well system, the well system being represented by a number of branches (1,1a) conducting hydrocarbons from at least one branch entry point (3,3a) to a branch exit point (2), at least one of said branches constituting a global well system exit point, wherein each branch has a branch entry point (3,3a) being provided with a least one flow inlet (4) and being related to known boundary conditions and with a input flow control unit (7) being related to adjustable flow characteristics for controlling the flow through said input, said boundary conditions including predetermined data concerning at least one of pressure, temperature and flow at said input flow control unit, and said branch conduit includes an branch flow control unit (6), having adjustable flow characteristics for controlling the flow through the branch.

Abstract: Systems, methods, and other embodiments are disclosed that are configured to segment customers using mixed attribute types. In one embodiment, a computerized data structure is read. The computerized data structure has numerical demographic attribute data, categorical demographic attribute data, and target attribute data that is associated with customers and is stored in a computerized memory. The numerical demographic attribute data and the categorical demographic attribute data are converted to a same numerical scale, based at least in part on the target attribute data, to form congruent attribute data in a format that is compatible with performing a cluster analysis on the congruent attribute data. The cluster analysis is performed on the congruent attribute data to generate segmented customer data representing a segmentation of the customers. The segmented customer data may be used to control at least one enterprise function performed by a computerized management system.

Abstract: A global fluid identity repository is used to maintain and manage fluid characterization data for various fluids utilized in the oil & gas industry, e.g., reservoir fluids within subsurface formations. Tracking and notification services may be utilized to track changes made to a global fluid identity, e.g., changes in fluid sample and/or experiment data for a fluid, and automatically generate notifications when downstream data such as fluid models and/or simulation results become stale as a result of these changes.

Abstract: An intelligent data management system leverages heterogeneous database technologies and cloud technology to manage data for reservoir simulations across the lifetime of a corresponding energy asset(s) and facilitates access of that data by various consumers despite changing compute platforms and adoption of open source paradigms. The intelligent data management system identifies the various data units that constitute a reservoir simulation output for storage and organization. The intelligent data management system organizes the constituent data units across a file system and object database based on correspondence with different simulation run attributes: project, study, and model. The intelligent data management system also learns to specify or guide configuration of simulation runs.

Abstract: A computer simulation analysis method suitable for describing the mechanical behavior of multiphase composites based on the real microstructure of materials relates to a multidisciplinary field such as computational material science, simulation and high throughput calculation. Through the first-principles calculation under nano scale, the molecular dynamics simulation under micro scale, and the thermodynamic calculation under mesoscopic scale, various physical parameters needed for the finite element simulation under macro scale can be obtained, including the elastic and plastic physical parameters of each phase in the composite at different temperature and different grain sizes. Focused ion beam experiment and image processing are adopted to obtain real material microstructure.

Abstract: A system and method of generating a wellbore layout are disclosed herein. A computing system receives, from a client device, one or more parameters associated with a target location for the target wellbore layout. The computing system receives, from the client device, one or more constraints for the target wellbore layout. The computing system generates a plurality target wellbore layout based on the parameters and constraints in accordance with a plurality of configurations as defined by one or more genetic algorithms. The computing system evaluates each target wellbore layout to generate an overall fitness score. The computing system selects a target wellbore layout with the highest scoring score of each generated overall fitness score, repeating the process until an optimal wellbore layout is selected.

Abstract: A drilling well underground kick processing method and device are described.

Abstract: A method for performing a field operation of a field. The method includes obtaining historical parameter values of a runtime parameter and historical core datasets, where the historical parameter values and the historical core datasets are used for a first simulation of the field, and where each historical parameter value results in a simulation convergence during the first simulation, generating a machine learning model based at least on the historical core datasets and the historical parameter values, obtaining, during a second simulation of the field, a current core dataset, generating, using the machine learning model and based on the current core dataset, a predicted parameter value of the runtime parameter for achieving the simulation convergence during the second simulation, and completing, using at least the predicted parameter value, the second simulation to generate a modeling result of the field.

Abstract: An apparatus for estimating a gas-oil ratio for a well in an unconventional reservoir comprises a processor associated with a control system. The processor is configured to determine a bottomhole pressure for the well. The processor is further configured to determine one or more pressure, volume, and temperature (PVT) properties associated with fluid flow and to determine transient well performance. The processor is further configured to determine a Productivity Index (PI) for the well for a plurality of time steps and to determine an inflection point. The processor is further configured to estimate the gas-oil ratio of the well after the inflection point based on the determined transient well performance and to perform the fluid production rate forecast based on the determined PI. The processor is further configured to apply the fluid production rate forecast to the estimated gas-oil ratio to determine an instantaneous gas-oil ratio.

Abstract: A method includes receiving a drill bit design. The design specifies a design parameter for a plurality of cutter elements of a drill bit. The method also includes estimating a temperature value for the cutter elements based on the design parameter and a drilling parameter; estimating a wear value for the cutter elements based on the design parameter and the temperature value; updating a value of the design parameter for at least one of the cutter elements based on the wear value and a time period; and using the updated design parameter value, repeating the steps of estimating the temperature value, estimating the wear value, and updating the design parameter value until the design parameter value for the at least one of the cutter elements reaches a threshold value.

Abstract: A flow field measurement device and a method for a scale model of a natural gas hydrate reservoir are provided. The measurement device includes non-central vertical well pressure sensors, non-central vertical well outlet valves, communicating vessel valves, differential pressure sensors, a communicating vessel, a central vertical well outlet valve, and a central vertical well pressure sensor. By providing differential pressure sensors, between a measuring point of the central vertical well and a measuring point of each of the non-central vertical wells, to measure pressure differences, the flow field measurement device enables a reasonable distribution of a three-dimensional space inside the reactor to analyze gas-liquid flow trends in the reactor with a simulated flow field. Determining whether to turn on the differential pressure sensors according to a predetermination based on a feedback from the pressure sensors, allows flow field measurements in the reactor under both high and low pressure differences.

Abstract: A method includes representing oilfield operational plan information as pixels where the pixels include pixels that correspond to a plurality of different state variables associated with oilfield operations; training a deep neural network based at least in part on the pixels to generate a trained deep neural network; implementing the trained deep neural network during generation of an oilfield operational plan; and outputting the oilfield operational plan as a digital plan that specifies at least one control action for oilfield equipment.

Abstract: The disclosure presents a technique to generate a fracture model using a differential stress map and model inputs. The technique simulates the fracture model using fracture fronts, initiated at perforations of a perforation stage of a hydraulic fracturing (HF) wellbore. Each fracture front is evaluated using a propagation step of a fracture model process. Using the relative differential stress states, a fracture pattern is composited to the fracture model. At each propagation step, the total energy available from the simulated HF fluid being pumped into the wellbore location is reduced by the amount necessary to generate the computed fractures. Once the remaining energy is reduced to a level where no further fractures can be created, or if a map boundary is encountered, the fracture model process terminates. The generated fracture model can be communicated to update HF job plans, wellbore placements, and other uses of the fracture model.

Abstract: The present disclosure provides a multi-scale three-dimensional (3D) engineering geological model construction system and method. A regional geological model of a target region, a site geological model of each engineering site, and a drilling geological model of each drilling well are constructed. The geological model of each drilling well is superimposed to the site geological model of the corresponding engineering site in the way of step-by-step superimposition, and the site geological model of each engineering site fused with the drilling geological model is superimposed to the regional geological model of the target region. Thus, multi-scale geological model fusion of drilling well, engineering site, and regional mountain is realized.

Abstract: A method includes designing a lower completion string for a multi-stage hydraulic fracturing job for a wellbore drilled into a subterranean zone. The lower completion string includes a plurality of stages and a plurality of packers configured to isolate each of the stages. Each stage of the plurality of stages includes a respective tubular stage assembly, and each stage is configured to be placed within a respective one of a plurality of frac intervals of the wellbore defined by the plurality of packers. Designing the lower completion string includes, for each stage of the plurality of stages, receiving a measured hole diameter of the respective one of the plurality of frac intervals and performing an axial safety factor analysis of the stage.

Abstract: Embodiments of determining a vertically transverse isotropy (VTI) anisotropy along a horizontal section of a wellbore drilled into a formation are provided. One embodiment comprises determining elastic constants C11, C44, and C66 of the horizontal section and determining a vertical compressional slowness of the horizontal section corresponding to an elastic constant C33 of the horizontal section using a model with a condition. The model is built using second sonic log data and second density log data of the vertical wellbore. The condition is that the shear slowness (DTS) of the vertical wellbore is equal to the vertically polarized shear slowness (DTSV) of the horizontal section. The embodiment further comprises determining a VTI anisotropy along the horizontal section using the elastic constants C11, C44, C66, and C33 of the horizontal section.

Abstract: A system, method and program product for implementing a machine learning platform that processes a data map having feature and operational information. A system is disclosed that includes an interpretable machine learning model that generates a function in response to an inputted data map, wherein the data map includes feature data and operational data over a region of interest, and wherein the function relates a set of predictive variables to one or more response variables; an integration/interpolation system that generates the data map from a set of disparate data sources; and an analysis system that evaluates the function to predict outcomes at unique points in the region of interest.

Abstract: Methods and apparatus for inspecting oilfield infrastructure components. Methods include methods of identifying a micro-annulus outside a casing in a cemented wellbore. Methods may include transmitting an acoustic pulse incident on the casing; making a measurement of a first acoustic impedance property value from pulse-echo information generated responsive to an echo of the acoustic pulse reflected from the casing; propagating a circumferential guided wave in the casing; making a measurement of a second acoustic impedance property value from propagating wave information generated responsive to the propagating acoustic wave; and determining from the first acoustic impedance value and the second acoustic impedance value a presence of a micro-annulus between the casing and the cement.

Abstract: Methods for predicting hydrocarbon production rates for a hydrocarbon reservoir include receiving data from a hydrocarbon reservoir. The data includes reservoir characterization data, well log data, and hydraulic fracturing data. A physics-constrained machine learning model predicts a hydrocarbon production rate for the hydrocarbon reservoir as a function of time. The physics-constrained machine learning model includes an artificial neural network and a hydrocarbon fluid flow model. Predicting the hydrocarbon production rate includes generating, by the artificial neural network, multiple parameters of the hydrocarbon fluid flow model based on the data from the hydrocarbon reservoir. The hydrocarbon fluid flow model provides the predicted hydrocarbon production rate as a function of time based on the parameters. A display device of the computer system presents the predicted hydrocarbon production rate for the hydrocarbon reservoir as a function of time.

Abstract: Methods for training machine learning algorithms for generation of a reservoir digital twin include receiving information obtained from hydrocarbon wells. The information includes porosity logs, petrophysical data, rock typing data, pressure transient test results, vertical production logs, reservoir pressure logs, reservoir saturation logs, production performance, and injection performance. The reservoir saturation logs are normalized in accordance with time. A machine learning algorithm is trained using the reservoir pressure logs, the production performance, and the injection performance to provide variations in reservoir pressure of the hydrocarbon reservoir in accordance with time. The machine learning algorithm is trained to provide variations in reservoir saturation of the hydrocarbon reservoir in accordance with time.

Abstract: Component weight and/or volume fractions of subterranean rock are determined. A formation model generates mineral and fluid concentration data from which elemental concentrations are calculated. Forward modeling produces a simulated energy spectrum, and simulation produces a simulated constraining log. Spectra is generated by detecting gamma radiation with a neutron logging tool, and a constraining log is generated. The spectrum and the simulated energy spectrum are compared with resultant error determined. The constraining log and simulated constraining log are compared with resultant error determined. The formation model generates further mineral and fluid concentration to calculate further elemental concentrations. Forward modeling produces further simulated energy spectrum signal and further constraining logs. The spectrum signals and further simulated spectrum signal are compared with resultant error determined.

Abstract: Systems and methods for multiscale sectors based hydrocarbon reservoir simulation that include dividing a full-field reservoir model into regions and sub-regions, and iteratively assessing and reconnecting models of the sub-regions and regions in a sequential manner to generate an adjusted full-field model.

Abstract: A computer-implemented method may include receiving test data representing a cutter/rock interaction for a cutter/rock pair; calibrating an analytical model to represent the cutter/rock interaction mechanism for a cutter/rock pair; applying the calibrated analytical model to expand the test data to form one of a plurality of expanded test datasets; generating a first neural network model, of a plurality of first neural network models, representing cutter/rock interaction between a plurality of cutters of different cutter sizes and a particular rock type, wherein the first neural network is generated using the plurality of expanded test datasets as training input; generating a second neural network model using the plurality of first neural network models as training input, wherein the second neural network model represents non-tested cutter/rock interactions between a plurality of cutters of different cutter sizes and a plurality of rock types.

Abstract: A method and system for modeling a subsurface region include applying a trained machine learning network to an initial petrophysical parameter estimate to predict a geologic prior model; and performing a petrophysical inversion with the geologic prior model, geophysical data, and geophysical parameters to generate a rock type probability model and an updated petrophysical parameter estimate. Embodiments include managing hydrocarbons with the rock type probability model.

Abstract: In an example method, one or more processors receive a plurality of rock fragment images. Each of the rock fragment images represents respective rock fragments obtained from a subsurface formation during well bore drilling. The one or more processors select one or more portions of the rock fragment images, and generate a geological formation image based on the one or more selected portions of the rock fragment images. The geological formation image is indicative of one or more geological characteristics of the subsurface formation along the well bore.

Abstract: Geologic modeling methods and systems disclosed herein employ fault face parameterization to constrain and improve the transformation of a faulted physical space geologic model into an unfaulted depositional space geologic model. An illustrative embodiment includes: associating a seismic image with each face of at least one fault in a subsurface region; determining a correspondence map between the seismic images for said at least one fault; parameterizing the faces using the correspondence map to match parameter value assignments for corresponding portions of the faces; creating a displacement map that draws together matching parameter values to align the corresponding portions of the faces; applying the displacement map to the geologic model to create a design space model; modifying the design space model; applying the displacement map in reverse to the modified design space model to obtain a modified geologic model; and outputting the modified geologic model.

Abstract: The invention discloses a mechanics calculation method of drill bit tooth considering rock dynamic strength and mixed crushing mode, including: Step S1: selecting a target drill bit tooth and a target rock, and determining a type of target drill bit tooth, a geometry of the target drill bit tooth, a rock type and rock parameters of the target rock; Step S2: calculating a horizontal cutting force of the target drill bit tooth according to a horizontal cutting mechanics calculation method of drill bit tooth; Step S3: calculating a vertical penetration force of the target drill bit tooth according to a vertical penetration mechanics calculation method of drill bit tooth; Step S4: calculating a resultant force experienced by the target drill bit tooth according to a resultant force calculation method of drill bit tooth. The invention provides a calculation method for accurately obtaining drill bit tooth mechanics under different working conditions.

Abstract: The present disclosure relates to a method for determination of a real subsoil geological formation. In at least one embodiment, the method includes receiving a model representing the real subsoil. The model includes a shore line and a fluvial formation connected to the shore line at a point of the model. The shore line divides the model into a marine zone and a continental zone. The method further includes determining a delta zone in the model based on the shore line and based on the fluvial formation, determining a stochastic trajectory in said delta zone, and determining a lobe formation in said delta zone based on the determined stochastic trajectory based on a stochastic process.

Abstract: The invention discloses a method for improving a recovery ratio of a braided well pattern of a hugely thick or multi-layer oil and gas reservoir, which improves the recovery ratio of the hugely thick or multi-layer oil and gas reservoir by designing the braided well pattern. The braided well pattern is designed through the following method: dividing a cubic development unit of the oil and gas reservoir; measuring a physical property parameter of the cubic development unit; calculating a well pattern design parameter according to the physical property parameter, wherein the well pattern design parameter includes a number of wells and a well bore track; and drilling a large-displacement horizontal well according to the well pattern design parameter.