Petrographic data of a carbonate reservoir in a subterranean region is received. Mud content of the carbonate reservoir is determined based on the petrographic data. A depositional porosity of the carbonate reservoir is computed based on the mud content. An amount of cementation of the carbonate reservoir is determined. A porosity loss by compaction of the carbonate reservoir is determined based on the mud content and the amount of cementation of the carbonate reservoir. A post-compaction porosity of the carbonate reservoir is computed based on the depositional porosity, the mud content, the amount of cementation, and the porosity loss by compaction.

A method may include obtaining various well logs or various core samples regarding a geological region of interest. The method may further include determining various permeability values, various porosity values, and various dolomite volume fraction values regarding the geological region of interest using the well logs or the core samples. The dolomite volume fraction values may correspond to a percentage of dolomite in a total mineral volume. The method may further include determining, using the porosity values, various permeability thresholds corresponding to various predetermined reservoir qualities. The method may further include generating, using the permeability thresholds, the permeability values, and the dolomite volume fraction values, a reservoir model including various dolomite boundaries defining the predetermined reservoir qualities. The method may further include determining a hydrocarbon trap prediction using the reservoir model.

Systems, methods, and apparatuses for determining pore volume and pore volume compressibility of secondary porosity in rock samples is disclosed. In some implementations, determining a pore volume of a secondary porosity in a rock core sample may include saturating the rock sample with deuterium oxide (D2O) by applying a vacuum to the core sample covered by D2O; centrifuging the saturated rock sample at a selected rotational speed in the presence of a second fluid to displace a portion of the D2O from the rock sample with the second fluid; measuring the rock sample with low-field .sup.1 H nuclear magnetic resonance (NMR) to determine a volume of the second fluid within the rock sample; and determining a pore volume associated with a secondary porosity based on the volume of the second fluid within the rock sample.

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.

An oil well production method in which a plurality of producers are arranged in a horizontal direction, includes boring a monitor well adjacent to one of the producers in the horizontal direction, installing a measurement optical fiber cable in the monitor well, performing Brillouin measurement and Rayleigh measurement for a strain distribution, a pressure distribution, and a temperature distribution of the monitor well along the measurement optical fiber cable over a period in which a fracture occurs hydraulically in the producers and an oil producing period, analyzing data measured through the Brillouin measurement and the Rayleigh measurement, and determining an arrangement interval of the producers in the horizontal direction and a hydraulic fracturing parameter.

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.

An information processing system having a processor and a memory device coupled to the processor, wherein the memory device includes a set of instruction that, when executed by the processor, cause the processor to receive a multi-dimensional grid of acoustic or elastic impedances determined from seismic survey data associated with a subterranean formation, receive elastic property data that describes elastic property characteristics used to sort pseudo-components, and wherein the respective pseudo-components are formed of a combination of two or more lithologies. The instructions, when executed by the processor, further cause the processor to define select design variables using the impedance arrays, perform optimization operations for optimizing select design variables by applying the elastic property data as a part of a constitutive relation, and output a distribution of the pseudo-components to characterize volumetric concentrations of spatially grouped lithologies in a control volume of the subterranean formation.

A method includes receiving well log data for a plurality of wells. A flag is generated based at least partially on the well log data. The wells are sorted into groups based at least partially on the well log data, the flag, or both. A model is built for each of the wells based at least partially on the well log data, the flag, and the groups.

A method for determining a favorable time window of an infill well of an unconventional oil and gas reservoir, which comprises the following steps: S1, establishing a three-dimensional geological model with physical properties and geomechanical parameters; S2, establishing a natural fracture network model in combination with indoor core-logging-seismic monitoring; S3, calculating complex fractures in hydraulic fracturing of parent wells; S4, establishing an unconventional oil and gas reservoir model and calculating a current pore pressure field; S5, establishing a dynamic geomechanical model and calculating a dynamic geostress field; S6, calculating complex fractures in horizontal fractures of the infill well in different production times of the parent wells based on pre-stage complex fractures and the current geostress field; S7, analyzing a microseismic event barrier region and its dynamic changes in infill well fracturing; and S8, analyzing the productivity in different infill times, and determining an infill time window.

A system for estimating a property of a region of interest includes an acoustic measurement device including a transmitter configured to emit an acoustic signal having at least one selected frequency configured to penetrate a surface of a borehole in an earth formation and produce internal diffuse backscatter from earth formation material behind the surface and within the region of interest, and a receiver configured to detect return signals from the region of interest and generate return signal data. The system also includes a processing device configured to receive the return signal data, process the return signal data to identify internal diffuse backscatter data indicative of the internal diffuse backscatter, calculate one or more characteristics of the internal diffuse backscatter, and estimate a property of the region of interest based on the one or more characteristics of the internal diffuse backscatter.