A method for analyzing unconventional rock samples using nuclear magnetic resonance (NMR), tracking fluid change in the rock sample over a time period, calculating transverse relaxation time (T.sub.2) generating fluid distribution profiles by the computer processor and based on a NMR imaging, where the fluid distribution profiles representing a movement of the fluid, and obtaining, quantification of fracture volume by the computer processor and based on the NMR imaging.

A method for analyzing unconventional rock samples using nuclear magnetic resonance (NMR), tracking fluid change in the rock sample over a time period, calculating transverse relaxation time (T.sub.2) generating fluid distribution profiles by the computer processor and based on a NMR imaging, where the fluid distribution profiles representing a movement of the fluid, and obtaining, quantification of fracture volume by the computer processor and based on the NMR imaging.

The present invention provides a device and a method for measuring fluid saturation in nuclear magnetic resonance (NMR) on-line displacement, the method comprising: measuring a nuclear magnetic resonance (NMR) T2 spectrum under the dead volume filling of the on-line displacement system as displacing phase fluid and the core to be measured as saturated nuclear magnetic detection phase fluid to generate a calibrated T2 spectrum; measuring a nuclear magnetic resonance (NMR) T2 spectrum of a process in which the core to be measured is converted from a saturated displaced phase fluid into a displacing phase fluid to generate a displacement process T2 spectrum; generating the fluid saturation of the on-line displacement system in real time according to the generated calibrated T2 spectrum and the displacement process T2 spectrum. The present invention achieves the purpose of improving measurement precision of fluid saturation in the on-line displacement process.

The present invention provides a device and a method for measuring fluid saturation in nuclear magnetic resonance (NMR) on-line displacement, the method comprising: measuring a nuclear magnetic resonance (NMR) T2 spectrum under the dead volume filling of the on-line displacement system as displacing phase fluid and the core to be measured as saturated nuclear magnetic detection phase fluid to generate a calibrated T2 spectrum; measuring a nuclear magnetic resonance (NMR) T2 spectrum of a process in which the core to be measured is converted from a saturated displaced phase fluid into a displacing phase fluid to generate a displacement process T2 spectrum; generating the fluid saturation of the on-line displacement system in real time according to the generated calibrated T2 spectrum and the displacement process T2 spectrum. The present invention achieves the purpose of improving measurement precision of fluid saturation in the on-line displacement process.

An imaging device included in an assembly located in a wellbore during drilling operations may include a cylindrical housing that extends along a central axis thereof. The imaging device may include at least one gradient coil configured to produce a unique magnetic field weaker than a main magnetic field. The at least one gradient coil may create a variable field that is increased or decreased by changing a direction of the unique magnetic field with respect to a direction of the main magnetic field to allow a specific part of a rock formation to be scanned by altering and adjusting the main magnetic field. The imaging device may include at least one radio frequency coil configured to transmit radio frequency waves into the rock formation. The imaging device may include at least one magnet disposed in the cylindrical housing that resonates against the unique magnetic field.

An imaging device included in an assembly located in a wellbore during drilling operations may include a cylindrical housing that extends along a central axis thereof. The imaging device may include at least one gradient coil configured to produce a unique magnetic field weaker than a main magnetic field. The at least one gradient coil may create a variable field that is increased or decreased by changing a direction of the unique magnetic field with respect to a direction of the main magnetic field to allow a specific part of a rock formation to be scanned by altering and adjusting the main magnetic field. The imaging device may include at least one radio frequency coil configured to transmit radio frequency waves into the rock formation. The imaging device may include at least one magnet disposed in the cylindrical housing that resonates against the unique magnetic field.

A method for predicting formation permeability by measuring diffusional tortuosity in several directions by pulse gradient NMR. The method comprises evaluating an anisotropic diffusion coefficient by pulsed gradient NMR, determining diffusional tortuosity from the restricted diffusion data, supplementing the NMR results with resistivity and sonic logging data, measuring anisotropic tortuosity and porosity by resistivity and sonic data and combining all components in a single fitting model. The 11-coefficient model is trained to recognize the true values of permeability by comparing the real oil permeabilities measured. in a library of oil-carrying rock cores with the NMR, resistivity and sonic correlates The fitting coefficients are extracted by minimizing the discrepancy between the laboratory measured permeabilities and the predicted values combining all rapid logging information components with the agreement-maximizing weights.

A method for predicting formation permeability by measuring diffusional tortuosity in several directions by pulse gradient NMR. The method comprises evaluating an anisotropic diffusion coefficient by pulsed gradient NMR, determining diffusional tortuosity from the restricted diffusion data, supplementing the NMR results with resistivity and sonic logging data, measuring anisotropic tortuosity and porosity by resistivity and sonic data and combining all components in a single fitting model. The 11-coefficient model is trained to recognize the true values of permeability by comparing the real oil permeabilities measured. in a library of oil-carrying rock cores with the NMR, resistivity and sonic correlates The fitting coefficients are extracted by minimizing the discrepancy between the laboratory measured permeabilities and the predicted values combining all rapid logging information components with the agreement-maximizing weights.

A porosity model of a core sample obtained from a subterranean formation is determined. The porosity model includes a macroporosity group and a microporosity group. A nuclear magnetic resonance (NMR) measurement is performed to obtain an NMR T.sub.2 distribution of the core sample at 100% water saturation. A desaturation step is performed on the core sample. An NMR measurement is performed for the desaturation step to obtain an NMR T.sub.2 distribution of the core sample. A resistivity index of the subterranean formation is determined at least based on the porosity model and each of the NMR T.sub.2 distributions.

A method for combining nuclear magnetic resonance (NMR) analysis and digital rock physics (DRP) analysis based on drilling cuttings or other rock samples for improved downhole nuclear magnetic resonance validation and characterisation. A system for performing the method also is provided.