The present invention provides a method for estimating fluid saturation of a hydrocarbon-bearing rock from a rock image. The image is segmented to represent either a pore space or solid material in the rock. An image pore volume is estimated from the segmented image, and a corrected pore volume is determined to account for the sub-resolution pore volume missing in the image of the rock. An image-derived wetting fluid saturation of the rock is estimated using a direct flow simulation on the rock image and corrected for the corrected pore volume. A backpropagation-enabled trained model can be used to segment the image. A backpropagation-enabled method can be used to estimate the fluid saturation using an image selected from a series of 2D projection images, 3D reconstructed images and combinations thereof.

The device comprises: a measurement cell, configured for receiving a sample of porous medium containing a fluid comprising one or more phases; a X-ray source, configured for illuminating the measurement cell with X-rays; a detector, placed opposite the X-ray source with regards to the measurement cell, the detector being configured for receiving X-rays arising from the sample contained in the measurement cell. The X-ray source is configured for illuminating simultaneously at least a surface of the sample without relative movement between the X-ray source and the sample, the detector comprising a plurality of sensing areas configured for selectively detecting X-rays arising from different points on the surface of the sample.

A method for determining properties of a 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 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 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, a radial profile of oil saturation, and a radial profile for pore aspect ratio.

The present invention discloses a method of separating, identifying and characterizing cracks in 3D space, which processes as follows to a volumetric image, so as to perform the separation, identification and the characterization of the cracks in the 3D space: 1) preprocessing digital image; 2) statistically analyzing basic information of the digital image: the basic information of the image includes porosity, connectivity of each pore, statistics of pore size, and position, size, orientation and anisotropy of each pore-structure; 3) filtration: removing non-crack structure in the image; 4) smoothening: smoothening and mending the image; 5) thinning: thinning the void structure into a thickness d (d can be any value, but more appropriate to be 2 to 3 voxels generally) in a direction with shortest extension in the 3D space; 6) separation: separating intersected cracks in a crack network by breaking the connections; 7) combination: combining those elongated cracks that are disconnected in the last step, merging tiny structures that are formed during the separation to a nearby large cluster, and restoring cracks to the thickness before thinning, and eventually giving out the characterization of the cracks. In the following expression, the wording “void” is used more, emphasizing the “empty” gap in the image rather than the rock solid. In this patent application, it is mainly for the case where the void appears in a state of crack, not excluding the case where the void appears in a state of small pore.

A system and method for estimating porosity distribution in a region of interest of a geologic formation from a resistivity image log representative of the geologic formation is disclosed. A normalization factor representative of a rock matrix based on a first resistivity value and an image point factor based on a second resistivity value are calculated and compared to identify points in the resistivity image log that correspond to the secondary porosity. The normalization factor and image point factor are recalculated based on a different first resistivity value and a different second resistivity value as necessary to identify additional points in the resistivity image log that correspond to the secondary porosity until a termination criterion is met. The method may further include a porosity calibration operation and one or more artifact corrections.

A method of a nuclear magnetic resonance measurement of a crushed porous media sample, including where the crushed pieces of the sample are not smaller than the pore size of the porous media, the surfaces of the sample are wet with a liquid and the pores of the sample are saturated with a fluid, subjecting the sample to a centrifugal force, performing a nuclear magnetic resonance measurement of the sample, and determining a petrophysical property of the sample from data acquired from the acquisition scan.

A porous sample is alternately saturated with at least two saturating fluids with known different thermal conductivities. As at least one saturating fluid a mixture of at least two fluids is used with known and different thermal conductivities. After each saturation thermal conductivity of the saturated sample is measured, and pore space characteristics and matrix thermal conductivity are determined based on the results of thermal conductivity measurements.

The system includes a gas tank. A reference volume is fluidly coupled to the gas tank. A coreholder fluidly is coupled to the reference volume. A sample is disposed in the coreholder. A fluid pump is fluidly coupled to the coreholder. A first pressure transducer is fluidly coupled between the fluid pump and the coreholder. The first pressure transducer measures a confining pressure. A second pressure transducer is fluidly coupled to the coreholder. The second pressure transducer measures upstream pressure within the coreholder.

A method for determining characteristics of a mesoporous material using a desiccation or hydration test is disclosed. The test may involve using a test fluid and exposing sample of a core to a controlled environment, then weighing the samples. The samples may be core samples, comminuted samples, or cuttings. Utilizing the determined characteristics, properties of the mesoporous material, such as porosities, absolute permeabilities and relative permeabilities may be determined.

The effect of drilling fluids on particular subterranean environments can be analyzed to improve the formation of drilling fluids and additives such as lost circulation materials. A plug can be generated by a particle plugging apparatus by injecting lost circulation material into the particle plugging apparatus. A set of tests to be performed on the plug can be identified. The set of tests can include at least one physical test and at least one electronic test. A test schedule indicating the order in which each test of the set of tests is to be performed can be defined. The set of tests can be executed to generate a testing output. The testing output can be used to generate a three-dimensional network model of the plug.