An apparatus for analyzing a core sample obtained from a subterranean formation includes a neutron generator, a plurality of detectors, a computed tomography scanner, an information processing device, and a transport system. The neutron generator can operate in a pulsed mode and emit neutrons into the core sample.

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.

A yield estimation device for a low-yield shale gas reservoir includes: a separation tank, a pulse gas detector, and a methane concentration detector; wherein a liquid inlet is provided at an upper portion of the separation tank; an exhaust pipe is provided on a top of the separation tank, and the pulse gas detector is installed at a middle section of the exhaust pipe; the methane concentration detector is installed at a tail end of the exhaust; a valve is installed in a liquid outlet; a float is arranged in the separation tank, which is connected to the valve through a telescopic float rod. A yield estimation method includes steps of: inputting flowback fluid into the separation tank through the liquid inlet; discharging the air in the separation tank; performing gas-liquid separation; detecting and displaying the shale gas in real time with the pulse gas detector.

A carbonate microfluidic model with controllable nanoscale porosity and methods are described. The method for fabricating a carbonate nanofluidic micromodel with controllable nanoscale porosity for studying fluid behaviors in an underground oil-reservoir environment includes: disposing a plurality of polymer spheres into a transparent flow cell; initiating crystallization of the plurality of polymer spheres to form a template with an opal structure; filling the transparent flow cell with a calcium-based solution and a carbonate-based solution to form nanocrystals in voids of the opal structure; and removing the template formed by crystallization of the plurality of polymer spheres from the transparent flow cell leaving an inverse opal structure with a plurality of nanoscale pores and a carbonate surface. The model includes: a transparent flow cell including a first end defining an inlet and a second end defining an outlet; and an inverse opal structure of carbonate inside the transparent flow cell.

Methods and systems are provided that combine NMR and IR spectroscopy measurements on a rock sample to determine data representing at least one property of the rock sample. In one embodiment, cuttings can be split into first and second lots. Results of an NMR measurement performed on the first lot of cuttings without cleaning can be analyzed to determine pore volume of the cuttings. Results of an IR spectroscopy measurement performed on the second lot of cuttings after solvent cleaning can be analyzed to determine matrix density of the cuttings. Porosity can be determined from the pore volume and matrix density of the cuttings. In another embodiment, combined NMR and IR spectroscopy measurements can be performed on an unprepared rock sample (without solvent cleaning) to characterize properties of kerogen in the rock sample and porosity. In another aspect, a method is provided that employs multi-nucleic NMR measurements to determine porosity.

A method for predicting a total minimum horizontal stress (σ.sub.h) and a total maximum horizontal stress (σ.sub.H) for an anisotropic formation may comprise: measuring Young's moduli parallel ±15° and perpendicular ±15° to a transverse isotropy plane of a horizontal core sample from the anisotropic subterranean formation; measuring Poisson's ratios parallel ±15° and perpendicular ±15° to the transverse isotropy plane of the horizontal core sample; inputting the measured Young's moduli and Poisson's ratios of the horizontal core sample into a 1-dimensional mechanical earth model (1-D MEM); and calculating, using the 1-D MEM, a predicted total minimum horizontal stress (σ.sub.h) and a predicted total maximum horizontal stress (σ.sub.H).

This invention relates to a method of estimating the organic carbon content of soil or changes in organic carbon content of the soil over time using Loss On Ignition (LOI) in which a first sample of the soil is taken from a selected location and heated by forcing heated oxygen-containing gas through the soil sample, monitoring the temperature of the sample by using at least one temperature sensing means within the soil sample and varying the supply of the gas to the sample in accordance with the temperature of the sample as sensed by the sensing means to remove organic materials including organic carbon from the soil sample by burning off or oxidising the organic materials.

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for detecting seepage of hydrocarbons in subterranean zones. In one aspect, a method includes detecting hydrocarbon seepage at multiple different sampling depths from a surface in a surveyed geographic region, comparing each of the hydrocarbon seepage at the multiple different sampling depths, wherein hydrocarbon seepage at a reference depth is known, and determining hydrocarbon seepage through the surveyed geographic region based on a result of the comparison.

Systems, methods, and apparatuses for detecting and collecting fluids released into a body of water are disclosed. Particularly, detection and collection of a fluid released during a petroleum exploration or production operation are disclosed. A released fluid may be detected using sensors on a submersible vehicle (SV) or a plurality of SVs operating in concert. A detected released fluid is collected in storage tanks onboard of the one or more SVs or in an external tank coupled to the one or more SVs.

Methods are provided for characterizing organic matter in a geological rock formation that perform a Raman spectroscopy measurement on a rock sample of the formation to acquire a Raman spectrum of the rock sample. At least one processor is used to perform operations that involve i) analyzing the Raman spectrum of the rock sample to determine data characterizing at least one Raman spectral feature corresponding to the rock sample, ii) inputting the data characterizing the at least one Raman spectral feature corresponding to the rock sample into a computation model that determines a value of a property of organic matter in the rock sample given the data characterizing the at least one Raman spectral feature as input, and storing or outputting or displaying the value of the property of organic matter in the rock sample. In embodiments, the property of organic material in the rock sample can be a property of kerogen in the rock sample, or a property of asphaltenes or bitumen in the rock sample.