A method for determining lower radius limit of movable throat of shale is provided, and it includes: performing a low-temperature nitrogen adsorption test on a target shale to obtain first pore radii; performing a high-pressure mercury injection test on the target shale to obtain second pore radii; performing a nuclear magnetic resonance test on the target shale to obtain third pore radii; obtaining a relationship diagram of distribution frequencies and pore radii according to three pore radii; distinguishing, according to the pore radii, relationship diagram data, and performing normalization processing to determining a relationship curve of normalized frequency data and the pore radii; and determining a lower radius limit of movable throat of shale according to relationship curve. A problem of describing characteristics of shale occurrence space with complex pore structures and strong heterogeneity is solved, the method is suitable for determining lower radius limit of movable throat of shale.

The disclosure is directed to a method, and system for analyzing a subterranean formation for designing an oil field service to be completed in a borehole of the subterranean formation for enhancing recovery of oil or gas from the formation. The subterranean formation may be an unconventional reservoir.

A method can include receiving porosimetry data for a range of pressures that spans a transition zone defined at least in part by a high-pressure end of a first pressure zone and a low-pressure end of a second pressure zone; detecting at least one artifact in the transition zone; computing accuracy information for the high-pressure end of the first pressure zone and the low-pressure end of the second pressure zone; computing a pressure-volume adjustment based at least in part on the accuracy information; and outputting a pressure-volume relationship in the transition zone based at least in part on the pressure-volume adjustment.

Embodiments of a method of pore type classification for petrophysical rock typing are disclosed herein. In general, embodiments of the method utilize parameterization of MICP data and/or other petrophysical data for pore type classification. Furthermore, embodiments of the method involve extrapolating, predicting, or propagating the pore type classification to the well log domain. The methods described here are unique in that: they describe the process from sample selection through log-scale prediction; PTGs are defined independently of the original depositional geology; parameters which describe the whole MICP curve shape can be utilized; and objective clustering can be used to remove subjective decisions. In addition, the method exploits the link between MICP data and the petrophysical characteristics of rock samples to derive self-consistent predictions of PTG, porosity, permeability and water saturation.

Methods of conducting perforation and hydraulic fracturing operations in a subterranean wellbore by analysis of rock samples collected during drilling of the borehole. The rock samples can be analyzed on-site or off-site to characterize the connected porosity of the rock of the frac stages of the wellbore, enabling identification of the frac stages with the highest connected Porosity. The perforation and fracking procedures of higher-quality (high connected porosity) stages of the wellbore are prioritized over the poorer-quality (low connected porosity) stages, thereby enhancing oil and/or gas recovery from the subterranean formation, and reducing costs by avoiding frac stages which will be low producers due to their low connected porosity values.

A method for determining rock microscopic physical parameters and an apparatus may determine, based on the acquired macroscopic physical parameters and capillary pressure curve experimental data of a rock, a volume and a saturation of a nonwetting phase fluid injected into different pore throat distribution intervals, and calculate microscopic physical parameters of the rock, through which the properties of the rock, such as a pore structure, storage, seepage and the like can be depicted, thereby facilitating evaluation of hydrocarbon occurrences of a reservoir and formulation of a reasonable hydrocarbon field development strategy.

A method for calculating a surface relaxation rate of a shale includes: a relaxation time T distribution curve and a pore throat radius r distribution curve are obtained through experiments; abscissas of the two distribution curves are standardized, and the abscissa of the relaxation time T distribution curve is expanded or shrunk to ensure an abscissa value corresponding to a maximum ordinate value in the transformed relaxation time T distribution curve is same as an abscissa value corresponding to a maximum ordinate value in the pore throat radius r distribution curve; straight lines with a number of N parallel to a y-axis of a combined curve graph including the two distribution curves are drawn and a value corresponding to each straight line is calculated; and value with the number of N are processed to obtain a final surface relaxation rate .

A method for combined characterization of pore structure includes steps as follows. Firstly, CO.sub.2, N.sub.2 and high-pressure mercury intrusion porosimetry characterization curves are plotted based on actual measurement data, then, average values of the overlapping range of the CO.sub.2 and N.sub.2 characterization curves are calculated, and a function y.sub.i=(x) is fitted. Each pore volume y.sub.i corresponding to each pore diameter x.sub.i is calculated, and a curve is plotted with x.sub.i as a horizontal coordinate and y.sub.i as a vertical coordinate, thereby obtaining a characterization curve of the overlapping range between CO.sub.2 and N.sub.2 adsorptions. The same data processing is used to process the overlapping range data of the N.sub.2 and high-pressure mercury intrusion porosimetry characterization curves, to obtain the characterization curve between them. The characterization curves are spliced with the original CO.sub.2, N.sub.2, and high-pressure mercury intrusion porosimetry characterization curves to obtain a combined characterization curve.

A method of estimating a depth of a hydrocarbon-water contact of a hydrocarbon reservoir in a structure. The method may include the steps of analysing one or more samples obtained from the structure to generate a relationship relating resistivity to hydrocarbon-water contact depth, obtaining a resistivity measurement of the hydrocarbon reservoir, and estimating the hydrocarbon-water contact depth from the relationship relating resistivity to hydrocarbon-water contact depth and the resistivity measurement of the hydrocarbon reservoir.

A carbon film is formed from carbon nanotube assemblies. In the carbon film, a pore distribution curve indicating the relationship between the pore size and the Log differential pore capacity obtained based on mercury intrusion porosimetry has at least one peak with a log differential pore capacity of 1.0 cm.sup.3/g or more within a pore size range of 10 nm or more and 100 m or less.