Abstract: The method comprises feeding a second fluid in a porous sample; measuring a resistivity or/and conductivity in a plurality of regions having different second fluid contents in the porous sample; and repeating the following steps. Determining an estimated local volume of first fluid contained in each region from the resistivity or/and conductivity measured in the region and from an estimated value of the representative parameter; calculating an estimated total volume of first fluid in the porous sample from each estimated local volume of first fluid contained in each region; and modifying the value of the estimated representative parameter to minimize the difference between the estimated total volume and a measured total volume of fluid produced from the porous sample, the representative parameter of the porous sample being the estimated representative parameter minimizing said difference.

Abstract: The method comprises the following steps providing a porous sample containing a first fluid; establishing a steady state profile of a second fluid content in the porous sample by applying a first mechanical load, to create a plurality of regions having different second fluid contents in the porous sample; measuring, in each of the plurality of regions, a local saturation in the first fluid or/and in the second fluid; measuring, in each of the plurality of regions, a corresponding local electrical resistivity and/or conductivity; and determining a value of the representative parameter based on the corresponding values of local saturation and of local electrical conductivity and/or resistivity in each of the plurality of regions.

Abstract: The method comprises the following steps providing a porous sample containing a first fluid; establishing a steady state profile of a second fluid content in the porous sample by applying a first mechanical load, to create a plurality of regions having different second fluid contents in the porous sample; measuring, in each of the plurality of regions, a local saturation in the first fluid or/and in the second fluid; measuring, in each of the plurality of regions, a corresponding local electrical resistivity and/or conductivity; and determining a value of the representative parameter based on the corresponding values of local saturation and of local electrical conductivity and/or resistivity in each of the plurality of regions.

Abstract: The present invention relates to a method for determining a non-oil volume of a rock sample comprising: receiving a rock sample; and receiving a non-oil zone in a NMR map using a T1T2 sequence, the non-oil zone being associated to non-oil in the map; Then, determining a first NMR map of the received rock sample using a T1T2 sequence, and determining a volume of non-oil in the received rock sample based on an integral in an integration zone of the firstNMR map. The integration zone of the first NMR map being determined based on the received non-oil zone, and a calibration value.

Abstract: A method for determining a relation between an initial saturation and a residual saturation in a first fluid in a porous sample, comprising the following steps saturating a porous sample with a second fluid; measuring a local volume of the second fluid in the porous sample; establishing a steady state profile of a saturation in the first fluid in the porous sample; generating a rise of a capillary ascension flow of the second fluid through the porous sample; during the capillary ascension flow, simultaneously measuring a local volume of the second fluid; and determining the relation between the initial saturation and the residual saturation based on the measured local volume.

Abstract: The present invention relates to a method for determining a non-oil volume of a rock sample comprising: receiving a rock sample; and receiving a non-oil zone in a NMR map using a T1T2 sequence, the non-oil zone being associated to non-oil in the map; Then determining a first NMR map of the received rock sample using a T1T2 sequence, and determining a volume of non oil in the received rock sample based on an integral in an integration zone of the firstNMR map. The integration zone of the first NMR map being determined based on the received non-oil zone, and a calibration_value.

Abstract: A nuclear magnetic resonance relaxation dispersion method to determine the wettability and other parameters of a fluid in a porous medium such as in an earth formation is provided. The method includes the steps of measuring the spin-lattice relaxation time T1 of the fluid in the porous medium at varying polarizing magnetic field strengths or nuclear Larmor frequencies; and determining whether the values of T1 at varying Larmor frequencies follow a dispersion curve that is characteristic of the parameter of the fluid in the porous medium to be determined.

Abstract: Systems and methods for determining T2 cutoff are described. T2 cutoff can be derived from magnetic susceptibility measurements. By providing a depth curve of T2cutoff, improved permeability estimations from NMR can be generated. By combining a magnetic susceptibility tool and an NMR tool, a dynamic T2cutoff can then be provided, together with the standard NMR log, according to some embodiments. According to some embodiments the improved permeability estimations can be provided automatically and in real time at the wellsite.

Abstract: Methods are described for wettability characterization based on NMR measurements, which are sensitive to the surface wetting conditions of oil and water at the pore scale. The described methods make use of surface relaxation effects on the NMR relaxation (T2). Workflows are described to obtain wettability profiles of a porous media such as a rock either in the native state or prepared to a certain state in the laboratory. An underlying forward model is also described for the mixed wet and fractionally saturated pore spectrum. Outputs of the described inversion include continuous saturation and wettability profiles as a function of the pore sizes in the porous media, as well as an averaged value for saturation and wettability over the entire pore spectrum.

Abstract: Systems and methods for quickly determining wettability using a derived relationship between the two Nuclear Magnetic Resonance (NMR) relaxation times T1,oil and T2,oil combined with downhole or laboratory based NMR measurements. The derived relationship between T1,oil, T2,oil and wettability can be developed empirically for example from core-sample data. Once the relationship is defined, it can be used in the field or laboratory to quickly determine wettability from NMR measurements that measure T1,oil and T2,oil directly, or a function depending on them.

Abstract: Systems and methods for determining T2 cutoff are described. T2 cutoff can be derived from magnetic susceptibility measurements. By providing a depth curve of T2cutoff, improved permeability estimations from NMR can be generated. By combining a magnetic susceptibility tool and an NMR tool, a dynamic T2cutoff can then be provided, together with the standard NMR log, according to some embodiments. According to some embodiments the improved permeability estimations can be provided automatically and in real time at the wellsite.

Abstract: Methods are described for wettability characterization based on NMR measurements, which are sensitive to the surface wetting conditions of oil and water at the pore scale. The described methods make use of surface relaxation effects on the NMR relaxation (T2). Workflows are described to obtain wettability profiles of a porous media such as a rock either in the native state or prepared to a certain state in the laboratory. An underlying forward model is also described for the mixed wet and fractionally saturated pore spectrum. Outputs of the described inversion include continuous saturation and wettability profiles as a function of the pore sizes in the porous media, as well as an averaged value for saturation and wettability over the entire pore spectrum.

Abstract: A nuclear magnetic resonance relaxation dispersion method to determine the wettability and other parameters of a fluid in a porous medium such as in an earth formation is provided. The method includes the steps of measuring the spin-lattice relaxation time T1 of the fluid in the porous medium at varying polarizing magnetic field strengths or nuclear Larmor frequencies; and determining whether the values of T1 at varying Larmor frequencies follow a dispersion curve that is characteristic of the parameter of the fluid in the porous medium to be determined.