Values for porosity and permeability of core samples in a borehole are estimated by generating radial waves with an acoustic source in fluid around the core sample, and measuring pressure in the fluid. Moreover, the acoustic source operates at frequency close to a resonant frequency of the core sample. After the acoustic source no longer operates at the resonant frequency, pressure in the fluid attenuates over time. The pressure attenuation is recorded by the pressure measurements, along with the pressure in the fluid at the first harmonic (spectral component). The pressure attenuation and spectral component each are dependent on porosity and permeability of the core sample. Thus values for the porosity and permeability are determined based on the arithmetic relationships between pressure attenuation and the spectral component and porosity and permeability.

A method and system are described for creating subsurface models that accounts for pore type influences. The method includes identifying pore types and properties based on pore types, constructing a subsurface model for a subsurface region and using the subsurface model in simulations and in hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.

An embodiment in accordance with the present invention includes a method for estimating the permeability of fractured rock formations from the analysis of a slow fluid pressure wave, which is generated by pressurization of a borehole. Wave propagation in the rock is recorded with TFI. Poroelastic theory is used to estimate the permeability from the measured wave speed. The present invention offers the opportunity of measuring the reservoir-scale permeability of fractured rock, because the method relies on imaging a wave, which propagates through a large rock volume, on the order of kilometers in size. Traditional methods yield permeability for much smaller rock volumes: well logging tools only measure permeability in the vicinity of a borehole. Pressure transient testing accesses larger rock volumes; however, these volumes are much smaller than for the proposed method, particularly in low-permeability rock formations.

Mapping is performed of chemostratigraphic signatures of hydrocarbon reservoirs in three dimensions. Up-scaled chemostratigraphic data from well cuttings and well cores are tied with high-resolution elastic wireline data at well locations in the reservoir. The wireline data is used to determine suitable seismic attributes for mapping the desired chemostratigraphic property, and are obtained by performing pre- and/or post-stack inversions. A multi-attribute template, derived from the well data, is developed to characterize the reservoir in terms of its chemostratigraphic properties. The seismic data is then inverted to map the chemostratigraphic signatures of reservoir in three dimensions.

Various embodiments include apparatus and methods to estimate formation mobility from Stoneley waveforms. An objective function can be generated that represents misfit between measured Stoneley pressure values and synthetic pressure values. A minimization process can be applied to the objective function to estimate formation mobility and intrinsic attenuation. Additional apparatus, systems, and methods are disclosed.

Values for porosity and permeability of core samples in a borehole are estimated by generating radial waves with an acoustic source in fluid around the core sample, and measuring pressure in the fluid. Moreover, the acoustic source operates at frequency close to a resonant frequency of the core sample. After the acoustic source no longer operates at the resonant frequency, pressure in the fluid attenuates over time. The pressure attenuation is recorded by the pressure measurements, along with the pressure in the fluid at the first harmonic (spectral component). The pressure attenuation and spectral component each are dependent on porosity and permeability of the core sample. Thus values for the porosity and permeability are determined based on the arithmetic relationships between pressure attenuation and the spectral component and porosity and permeability.

A method for determining an intersection between a polygon representing a boundary of a surface in an earth formation and a plane includes: receiving a polygon representing a boundary of a surface in an earth formation, the polygon having a series of straight segments with a point at each end of each of the segments; overlaying a cutting grid having grid planes over the polygon; identifying a specific pattern of two adjacent segments in the polygon by proceeding from a first segment to a second segment in a selected rotational direction; matching the specific pattern to a reference pattern; categorizing the point between the two adjacent segments as an intersection point or as a non-intersection point based on the reference pattern; the iterating the identifying, matching, and categorizing for each pair of adjacent segments in the polygon such that each point between adjacent segments in the polygon is categorized.

The embodiments of the present disclosure disclose a method and an apparatus for determining the permeability of the reservoir. The method comprises: acquiring logging data corresponding to the two zones at least; determining the permeability of a specified zone in the two zones at least based on logging data corresponding to the specified zone, wherein the specified zone represents any one of the two zones at least; setting weight values corresponding to the at least two zones respectively; and determining the permeability of the reservoir based on the weight values and the permeability respectively corresponding to the two zones at least. The technical solutions provided by the embodiments of the present disclosure can improve the accuracy of the determined permeability of the reservoir.

Identifying a low permeable conglomerate diagenetic trap can be implemented according to a method that comprises: determining a first relation curve between a depth and a critical physical property of a known diagenetic trap in a target work area, and a second relation curve between a reservoir physical property of the known diagenetic trap and a designated seismic attribute; determining a third relation curve between the depth and the critical physical property in the target work area and the designated seismic attribute according to the first relation curve and the second relation curve; and performing a diagenetic trap identification of the target work area according to the third relation curve. Identification accuracy of a low permeable conglomerate diagenetic trap can thereby be improved.

A method can include receiving a stimulated rock volume dimension for a hydraulic fracture in a reservoir where the stimulated rock volume dimension defines a stimulated rock volume region: refining a grid cell model of the reservoir based on the stimulated rock volume dimension by selecting a refinement technique from a group of refinement techniques and generating new finer grid cells in the grid cell model based on the selected refinement technique: assigning a physical property value to each of the new finer grid cells using one or more physical property values selected from a group of existing physical property values; and performing a fluid flow simulation using the grid cell model with the new finer grid cells and their assigned physical property values, and the group of existing physical property values to generate fluid flow simulation results.