Abstract: A liquid saturation may be identified from nuclear magnetic resonance (NMR) data having overlapping peaks indicative of two liquids by, generally, identifying a first endpoint based at least in part on the T2 NMR data for the first liquid, and identifying a second endpoint based at least in part on the T2 NMR data for the second liquid. Then, the liquid saturation is identified by relating a composition of the first liquid for an overlapping distribution region based at least in part on the first endpoint and the second endpoint. In some embodiments, the liquid saturation is identified based on an interpolation between the first endpoint and the second endpoint.

Abstract: A method for estimation of water properties and hydrocarbon properties in a subsurface formation includes acquiring a plurality of well log measurements from the subsurface formation. The water properties and the hydrocarbon properties are parameterized with respect to a selected set of well log measurements. A simultaneous or sequential inversion is performed to estimate the water properties and the hydrocarbon properties.

Abstract: A method for determining a wettability of a subterranean formation (or formation core) includes either deploying a nuclear magnetic resonance (NMR) logging tool in a subterranean wellbore or deploying a formation core sample in a laboratory based NMR tool. NMR measurements of the formation (or formation core) are obtained and used to compute the wettability. The NMR measurements are processed to generate a two dimensional diffusion relaxation map (a D/T2 map) which is in turn processed to compute the wettability.

Abstract: A method for estimation of water properties and hydrocarbon properties in a subsurface formation include acquiring a plurality of well log measurements from the subsurface formation. The water properties and the formation properties are parameterized with respect to a selected set of well log measurements. The parameterized water properties, the parameterized formation properties and the well log measurements are graphically displayed to estimate the water properties.

Abstract: A method for determining a volume of a constituent(s) in a geological formation may include generating an equation of state based upon log measurements for the geological formation, with the equation of state providing a correlation between the log measurements, determining a quality factor for the equation of state, and for each of a plurality of different constituents expected to be in the formation, determining a constituent compliance factor for each of the constituents. The method may further include determining an uncertainty for each constituent compliance factor, determining a likelihood that each constituent is present in the formation based upon the quality factor, the constituent compliance factor for the constituent, and the uncertainty for the constituent compliance factor, generating a volumetric model based upon the log measurements and the determined likelihoods of the constituents in the formation, and determining the volume of the constituent(s) based upon the volumetric model.

Abstract: A method for generating a model of a formation property includes acquiring a formation property measurement. A petrophysical quantity is inverted from the formation property measurement. A model is generated based on the inverted petrophysical quantity.

Abstract: A liquid saturation may be identified from nuclear magnetic resonance (NMR) data having overlapping peaks indicative of two liquids by, generally, identifying a first endpoint based at least in part on the T2 NMR data for the first liquid, and identifying a second endpoint based at least in part on the T2 NMR data for the second liquid. Then, the liquid saturation is identified by relating a composition of the first liquid for an overlapping distribution region based at least in part on the first endpoint and the second endpoint. In some embodiments, the liquid saturation is identified based on an interpolation between the first endpoint and the second endpoint.

Abstract: The presence of hydrocarbons in a subsurface formation fluid may be inferred from a determined salt concentration. A sodium nuclear magnetic resonance (NMR) measurement of a subsurface formation is obtained and a salt concentration of the fluid in the subsurface formation is determined from the sodium NMR measurement. Various operations may be performed using the determined salt concentration such as tracking injected water, monitoring flood fronts, improving reserves estimation, and designing enhanced oil recovery. A sodium index may be determined and used in conjunction with one or more other logs to determine a saturation of the subsurface formation. The one or more other logs may include a resistivity log, a dielectric log, a capture cross section (sigma) log, and a proton NMR log. Differentiation between bound water and free water can also be achieved using the sodium nuclear magnetic resonance measurement.

Abstract: Apparatus and methods for characterizing hydrocarbons in a subterranean formation include obtaining a sample of the subterranean formation; measuring, uphole, the porosity of the sample; using a nuclear magnetic resonance (NMR) tool downhole in the borehole, sending NMR pulse sequences configured for formation pore size and measuring NMR signals that characterize the formation at a location in the formation; analyzing the signals to find a gas porosity of the formation at the location; and determining a hydrogen index (HIg) of the subterranean formation from the gas porosity and from the porosity of the sample. The obtained HIg may then be used in conjunction with downhole NMR measurements to find corrected gas porosities at locations of the formation.

Abstract: A method for determining a wettability of a subterranean formation (or formation core) includes either deploying a nuclear magnetic resonance (NMR) logging tool in a subterranean wellbore or deploying a formation core sample in a laboratory based NMR tool. NMR measurements of the formation (or formation core) are obtained and used to compute the wettability. The NMR measurements are processed to generate a two dimensional diffusion relaxation map (a D/T2 map) which is in turn processed to compute the wettability.

Abstract: A method for estimation of water properties and hydrocarbon properties in a subsurface formation include acquiring a plurality of well log measurements from the subsurface formation. The water properties and the formation properties are parameterized with respect to a selected set of well log measurements. The parameterized water properties, the parameterized formation properties and the well log measurements are graphically displayed to estimate the water properties.

Abstract: A method for estimation of water properties and hydrocarbon properties in a subsurface formation includes acquiring a plurality of well log measurements from the subsurface formation. The water properties and the hydrocarbon properties are parameterized with respect to a selected set of well log measurements. A simultaneous or sequential inversion is performed to estimate the water properties and the hydrocarbon properties.

Abstract: A method for determining a volume of a constituent(s) in a geological formation may include generating an equation of state based upon log measurements for the geological formation, with the equation of state providing a correlation between the log measurements, determining a quality factor for the equation of state, and for each of a plurality of different constituents expected to be in the formation, determining a constituent compliance factor for each of the constituents. The method may further include determining an uncertainty for each constituent compliance factor, determining a likelihood that each constituent is present in the formation based upon the quality factor, the constituent compliance factor for the constituent, and the uncertainty for the constituent compliance factor, generating a volumetric model based upon the log measurements and the determined likelihoods of the constituents in the formation, and determining the volume of the constituent(s) based upon the volumetric model.

Abstract: A method includes obtaining measurements of a formation parameter prior to and after treatment of at least one formation penetrated a wellbore formed in the subsurface formation. The measurement correspond to a plurality of lateral depths of investigation. A difference is determined at each depth of investigation between the measurements made prior to and after the treatment. A skin effect is determined for each depth of investigation.

Abstract: A method for generating a model of a formation property includes acquiring a formation property measurement. A petrophysical quantity is inverted from the formation property measurement. A model is generated based on the inverted petrophysical quantity.

Abstract: A method of interpreting petrophysical measurement data include arranging measurements of at least one physical property of formations into a matrix representing the measurements and selecting a range of number of unobserved factors or latent variables for factor analysis. Factor analysis is performed on the measurement matrix and comprises performing factorization of measurements matrix into a number of factorsand performing rotation of the factorization results. Whether the factor loadings for each factor have achieved a “simple structure” is determined and either each of the selected number of factors is associated with a physical parameter of the formations, or one is added to the number of factors and factor analysis and rotation are repeated until factor loadings of all factors have achieved “simple structure” such that the each of the number of factors is associated with a physical property of the formations.

Abstract: Apparatus and methods for characterizing hydrocarbons in a subterranean formation including sending and measuring NMR signals; analyzing the signals to form a distribution; and estimating a property of a formation from the distribution, wherein the sending comprises pulse sequences configured for a formation pore size, and wherein the computing comprises porosity. Apparatus and methods for characterizing hydrocarbons in a subterranean formation including sending and measuring NMR signals; analyzing the signals to form a distribution; and estimating a property of a formation from the distribution, wherein the formation comprises a distribution of pore sizes of about 10 nm or more, and wherein the computing comprises natural gas composition.

Abstract: The presence of hydrocarbons in a subsurface formation fluid may be inferred from a determined salt concentration. A sodium nuclear magnetic resonance (NMR) measurement of a subsurface formation is obtained and a salt concentration of the fluid in the subsurface formation is determined from the sodium NMR measurement. Various operations may be performed using the determined salt concentration such as tracking injected water, monitoring flood fronts, improving reserves estimation, and designing enhanced oil recovery. A sodium index may be determined and used in conjunction with one or more other logs to determine a saturation of the subsurface formation. The one or more other logs may include a resistivity log, a dielectric log, a capture cross section (sigma) log, and a proton NMR log. Differentiation between bound water and free water can also be achieved using the sodium nuclear magnetic resonance measurement.

Abstract: A technique utilizes the acquisition of data via nuclear magnetic resonance at multiple depths of investigation in a well region. The acquired data is processed to estimate variable fluid mixture densities at different radial depths. The variable fluid mixture densities and a radial response from a density tool, for example, can be used to calculate an effective fluid mixture density and used to interpret density logs. Other logs such as neutron log, induction resistivity log, and dielectric permittivity log can be combined with NMR. For these tools a corresponding effective formation property can be calculated and used to determine other formation characteristics, such as total porosity, total density, dielectric permittivity, electric resistivity, and formation characteristics derivable from these.

Abstract: A method of interpreting petrophysical measurement data include arranging measurements of at least one physical property of formations into a matrix representing the measurements and selecting a range of number of unobserved factors or latent variables for factor analysis. Factor analysis is performed on the measurement matrix and comprises performing factorization of measurements matrix into a number of factors and performing rotation of the factorization results. Whether the factor loadings for each factor have achieved a “simple structure” is determined and either each of the selected number of factors is associated with a physical parameter of the formations, or one is added to the number of factors and factor analysis and rotation are repeated until factor loadings of all factors have achieved “simple structure” such that the each of the number of factors is associated with a physical property of the formations.