A method and system are described for creating a subsurface model. In this method, discontinuous functions are interpolated in a subsurface model. The method extrapolates specified values over discontinuous manifolds by embedding the manifold in a higher-dimensional space that amplifies distances across discontinuities and thus eliminates special consideration to prevent extrapolation across discontinuities. The resulting subsurface model may be used in reservoir simulations and hydrocarbon operations.

Born Scattering Inversion (BSI) systems and methods are disclosed. A BSI system may be incorporated in a well system for accessing natural gas, oil and geothermal reserves in a geologic formation beneath the surface of the Earth. The BSI system may be used to generate a three-dimensional image of a proppant-filled hydraulically-induced fracture in the geologic formation. The BSI system may include computing equipment and sensors for measuring electromagnetic fields in the vicinity of the fracture before and after the fracture is generated, adjusting the parameters of a first Born approximation model of a scattered component of the surface electromagnetic fields using the measured electromagnetic fields, and generating the image of the proppant-filled fracture using the adjusted parameters.

In one embodiment, a method includes facilitating a real-time display of drilling-performance data for a current well. The method further includes receiving new channel data for the current well from a wellsite computer system. The method also retrieving input data including historical drilling-performance data for an offset well relative to the current well. In addition, the method includes computing calculated data for the current well based on the channel data and the input data. Moreover, the method includes updating the real-time display with the calculated data.

In some embodiments, a method for locally lumped equation of state fluid characterization can include determining a set of components for the material balance calculations for a plurality of grid blocks of a reservoir. The plurality of grid blocks can experience different recovery methods between them. Lumping schemes can be determined for the plurality of grid blocks. Phase behavior calculations can be performed on the plurality of grid blocks, wherein different lumping schemes can be used across the plurality of grid blocks.

A method is claimed that includes obtaining a measured present-day value of at least one parameter for each member of a set of unvalidated geological layers arranged in order of increasing depth and iteratively selecting a member of the set as a current layer. For each current layer in turn, the method further determines an estimated archaic value of at least one parameter of the current layer based on its measured present-day value by applying an alternating cycle of decompaction followed by geomechnical modeling to predict a present-day value of the parameter of the current layer based on its estimated archaic value. The method still further determines a validated archaic value of at least one parameter of each current layer based on a difference between the predicted and the measured present-day values. A non-transitory computer readable medium storing instructions for validating the archaic value for each layer is claimed.

A process of constructing a micromodel for a multiple porosity system includes: drilling a well; coring the well for acquiring core plugs from the well; producing thin section images of the core plugs for acquiring a first feature of the core plugs; and transforming the thin section images to binary images.

Methods and systems for controlling a drilling operation in a subterranean formation are disclosed. The method includes generating a simulated well log based, at least in part, on a subset of an MWD log from a horizontal well, wherein the subset of the MWD log is for measured depths between a starting measured depth and an ending measured depth. The method further includes monitoring and/or controlling a drilling operation based, at least in part, on the simulated well log.

Systems and methods include a method for generating a real-time permeability log. Historical mud gas-permeability data is received from previously-drilled and logged wells. The historical mud gas-permeability data identifies relationships between gas measurements obtained during drilling and permeability determined after drilling. A formation hydrocarbon mobility model is trained using machine learning and the historical mud gas data. Real-time gas measurements are obtained during drilling of a new well. A real-time permeability log is generated for the new well using the formation hydrocarbon mobility model and real-time gas measurements.

A method may include transforming optical responses for a fluid sample to a parameter space of a downhole tool. The optical responses are obtained using a first operational sensor and a second operational sensor of the downhole tool. Fluid models are applied in the parameter space of the downhole tool to the transformed optical responses to obtain density predictions of the fluid sample. The density predictions of the first operational sensor are matched to the density predictions of the second operational sensor based on optical parameters of the fluid models to obtain matched density predictions. A difference between the matched density predictions and measurements obtained from a densitometer is calculated, and a contamination index is estimated based on the difference.

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.