A method of estimating one or more properties of an earth formation includes acquiring formation fluid data indicative of a qualitative property of a formation fluid in a near-field region of an earth formation surrounding a borehole, the near field region including a surface of the borehole, and acquiring acoustic data based on acoustic signals transmitted into a far-field region of the formation, and estimating a property of one or more fractures in the far-field region based on the acoustic data. The method also includes combining the formation fluid data and the acoustic data, and estimating, by a processing device, at least one fracture characteristic of the formation in the near-field region and the far-field region based on the combined data.

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for determining a mudweight of drilling fluids in a hydrocarbon reservoir. One computer-implemented method includes: receiving pore pressure data of a rock formation in the hydrocarbon reservoir; determining permeability data of fractures of the hydrocarbon reservoir; determining Hoek-Brown failure criterion data; and determining a safe mudweight window based on the pore pressure data of the rock formation, the permeability data of the fractures, and the Hoek-Brown failure criterion data.

Certain aspects and features relate to a system that projects an optimized foam-fluid-application scenario for to stimulate production from a hydrocarbon well. The optimized scenario can include a recommended chemical make-up for the foam entity as well as application parameters such those related to timing and duration. A hybrid discrete fracture network and multi-porosity (DFN-MP) model for fluid interaction with the formation where the well is located can be produced by a processing device. The hybrid DFN-MP model can be optimized using field simulation data for the formation. The optimized hybrid DFN-MP model can be used by the processing device to produce an optimized foam-fluid-application scenario, which can be communicated to at least one well and can be utilized to stimulate the well for increased production.

Systems, methods, and computer programs for monitoring a drilling operation in a subterranean formation include receiving, from a first sensor array, one or more seismic signals caused, at least in part, by the drilling operation in the subterranean formation; receiving, from the first sensor array, one or more electromagnetic signals generated by an electroseismic or seismoelectric conversion of the one or more seismic signals caused, at least in part, by the drilling operation in the subterranean formation; and determining a property of one or more of the drillstring and the subterranean formation based, at least in part, on the seismic signals and the corresponding electromagnetic signals received from the first sensor array. The first sensor array is arranged to monitor the drilling operation.

Permeability in earth models has three components: natural fracture, distinctive matrix permeability and porosity correlated matrix permeability. While matrix permeability is usually predictable from porosity and diagenesis effects, fracture permeability can be a highly uncertain parameter. The earth model permeability components are calibrated by determining fracture distribution and estimating fracture properties through an iterative optimization process. The calibration proceeds iteratively until the current estimate of calculated reservoir flow capacity is within acceptable accuracy limits to reservoir flow capacity indicated from production logging tool measurements.

A method for determining properties of a laminated formation traversed by a well or wellbore employs measured sonic data, resistivity data, and density data for an interval-of-interest within the well or wellbore. A formation model that describe properties of the laminated formation at the interval-of-interest is derived from the measured sonic data, resistivity data, and density data for the interval-of-interest. The formation model represents the laminated formation at the interval-of-interest as first and second zones of different first and second rock types. The formation model is used to derive simulated sonic data, resistivity data, and density data for the interval-of-interest. The measured sonic data, resistivity data, and density data for the interval-of-interest and the simulated sonic data, resistivity data, and density data for the interval-of-interest are used to refine the formation model and determine properties of the formation at the interval-of-interest. The properties of the formation may be a radial profile for porosity, a radial profile for water saturation, a radial profile for gas saturation, radial profile of oil saturation, and radial profiles for pore shapes for the first and second zones (or rock types).

Exemplary implementations may: obtain, from the electronic storage, geological data corresponding to the geographic volume of interest; generate a framework for sediment deposition using a first set of multiple physical, chemical, biological, and geological processes; generate a framework for diagenesis using a second set of multiple physical, chemical, biological, and geological processes; generate a representation of sediment deposition by applying the geological data corresponding to the geographic volume of interest to the framework for sediment deposition; generate a representation of diagenesis based on the framework for diagenesis and the representation of sediment deposition; and display the representation of sediment deposition and the representation of diagenesis on a graphical user interface.

Provided herein are systems and methods for hydraulic fracturing in earth. Systems may comprise a first well comprising sensors configured to collect sensor data at the first well. The calibration data may comprise sensor data, hydraulic fracture treatment conditions of the first well, geological data from an area containing the first well, or production date of oil or gas from the first well. The calibration data may be analyzed with the aid of one or more processors to generate an integrated 3-D model of hydraulic fracturing and fluid flow in the wellbore and reservoir of the first well. The system may further comprise a second well configured to operate according to simulation data generated from the integrated 3-D model of the first well and hydraulic fracture treatment conditions received from a user device. The user device may be configured to communicate with a server comprising the one or more processors.

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for determining a mudweight of drilling fluids in a hydrocarbon reservoir. One computer-implemented method includes: receiving pore pressure data of a rock formation in the hydrocarbon reservoir; determining permeability data of fractures of the hydrocarbon reservoir; determining Hoek-Brown failure criterion data; and determining a safe mudweight window based on the pore pressure data of the rock formation, the permeability data of the fractures, and the Hoek-Brown failure criterion data.

Properties of underground formations are obtained by performing simultaneous geostatistical inversion of two or more seismic datasets acquired over the same area. These methods enable simultaneous estimating quantitative changes in a hydrocarbon-producing field.