Abstract: The calibration of fracture models for naturally fractured reservoirs using fracture properties from X-ray micro-computed tomography (X-ray MicroCT). A core plug is obtained from a subsurface naturally fractured hydrocarbon reservoir, and a fracture property such as fracture porosity and a fracture effective permeability of the hydrocarbon reservoir are determined. A natural fracture model is generated using reservoir parameters and fluid flow paths, and fracture properties such as fracture porosity and a fracture effective permeability are determined from the natural fracture model. The fracture properties of the natural fracture model are calibrated using the fracture properties from the X-ray MicroCT analysis of the core plug.

Abstract: A process for the determining of sweet spot intervals based on a combination of rock quality, an in-situ stress regime, natural fractures, and the identification of fluid flow paths from the interaction of hydraulic fracturing and formation attributes. The process may include determining geological components, determining mechanical earth model outputs, and determining sweet spot intervals using additional data from fracture calibration tests. Systems and computer-readable media for the determining of sweet spot intervals are also provided.

Abstract: The calibration of fracture models for naturally fractured reservoirs using fracture properties from X-ray micro-computed tomography (X-ray MicroCT). A core plug is obtained from a subsurface naturally fractured hydrocarbon reservoir, and a fracture property such as fracture porosity and a fracture effective permeability of the hydrocarbon reservoir are determined. A natural fracture model is generated using reservoir parameters and fluid flow paths, and fracture properties such as fracture porosity and a fracture effective permeability are determined from the natural fracture model. The fracture properties of the natural fracture model are calibrated using the fracture properties from the X-ray MicroCT analysis of the core plug.

Abstract: A process for identifying natural fracture sweet spots in a hydrocarbon reservoir by integrating reservoir modeling components and reservoir dynamic data. A fracture density index (FDI) is determined using natural fracture predictions from geomechanics and identified fluid flow paths. Natural fracture sweet spots may be identified from the FDI and additional inputs such as a reservoir matrix model and dynamic reservoir properties. Systems and computer-readable media for identifying natural fracture sweet spots are also provided.

Abstract: Provided is hydrocarbon reservoir development that includes determining, based on fracture data, a two-dimensional (2D) fracture model including fracture lines representing locations of fractures in the reservoir, determining, based on the lines, a fracture density index (FDI) map including FDI values for cells representing the reservoir, including, for each cell, determining a FDI value based on proximity to the fracture lines, determining a circulation loss (CL) map including CL values for the cells, including, for each cell, determining a CL value based on proximity of the cell to locations of circulation loss events in the hydrocarbon reservoir, determining, based on the FDI map and the CL map, a correlation of FDI to CL for the reservoir, and drilling a hydrocarbon well based on the correlation.

Abstract: A process for the determining of sweet spot intervals based on a combination of rock quality, an in-situ stress regime, natural fractures, and the identification of fluid flow paths from the interaction of hydraulic fracturing and formation attributes. The process may include determining geological components, determining mechanical earth model outputs, and determining sweet spot intervals using additional data from fracture calibration tests. Systems and computer-readable media for the determining of sweet spot intervals are also provided.

Abstract: Systems, methods, and computer readable media for the identification of fluid flow paths from the combination of aperture determined from microresistivity logs and mechanical properties from a mechanical earth model for a strike-slip fault regime. Fluid flow paths may be identified from a combination of apertures, shear stress, and normal stress for fractures in a naturally fractured hydrocarbon reservoir.

Abstract: Systems and methods for developing hydrocarbon reservoirs based on constrained natural fracture parameters. A natural fracture modeling is generated for a reservoir, an initial set of fracture model parameters is determined, and a fracture model optimization is conducted to determine an optimized set of fracture model parameters. The optimized set of fracture model parameters are used as a basis for modeling the reservoir, and the modeling is used to generate a simulation of the reservoir.

Abstract: Systems and methods for developing hydrocarbon reservoirs based on constrained natural fracture parameters. A natural fracture modeling is generated for a reservoir, an initial set of fracture model parameters is determined, and a fracture model optimization is conducted to determine an optimized set of fracture model parameters. The optimized set of fracture model parameters are used as a basis for modeling the reservoir, and the modeling is used to generate a simulation of the reservoir.

Abstract: Systems, methods, and computer readable media for the determination of hydrogen sulfide (H2S) concentration and distribution in carbonate reservoirs using a mechanical earth model. Hydrogen sulfide (H2S) concentration in a carbonate reservoir n may be measured and correlated with horizontal maximum stresses of stress ratios determined using mechanical earth model for a strike-slip fault regime. The hydrogen sulfide (H2S) concentration at different depths in the carbonate reservoir may be determined using the correlation.

Abstract: Methods and systems for determining pore-volume of a fracture in a core plug. The method includes developing a grid block model constrained by fracture porosity estimated from a mechanical laboratory test, aperture calculation, and discrete fracture model validation. The method further includes determining the natural fracture porosity and pore volume from the equivalent medium for natural fractures, determining oil or gas reserves by calculating the fracture pore volume, and determining fracture porosity measurement from a test to calibrate 3D fracture models. The method also includes determining fracture porosity from a mechanical test, analyzing borehole image logs, developing a geomechanical model and fracture drivers, performing fracture model predictions, validating and calibrating the model, and determining fracture pore-volume of the core plug.

Abstract: 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.