Saudi Arabian Oil Company

Mohammed Boudjatit

Stacey Marie Althaus

Jin-Hong Chen

Hui-Hai Liu

Gary Eppler

Houzhu Zhang

Mustafa A Basri

Jilin Jay Zhang

Ihab S Mahmoud Aly

John David Broyles

Huihai Liu

Rebah Mesdour

Methods and systems are disclosed. The methods may include determining a first sequence of permeabilities by subjecting a rock sample to a first sequence of confining stress, axial stress, pore pressure (CSASPP) triplets and determining a first rock parameter using the first sequence of permeabilities, the first sequence of CSASPP triplets, and a first permeability model. The methods may further include determining a second sequence of permeabilities by subjecting the rock sample to a second sequence of CSASPP triplets and determining a second rock parameter using the second sequence of permeabilities, the second sequence of CSASPP triplets, and the first permeability model. The method may still further include determining an in situ permeability for an in situ rock based on an initial permeability, a second stress sensitivity parameter, a first stress sensitivity parameter, a confining stress value, axial stress values, a pore pressure value, and a second permeability model.

Systems and methods to determine permeability of rock under anisotropic stress

A method and system for determining a mass of an absorbed gas and a mass of a pore gas in a sample using NMR spectroscopy is provided. The method includes acquiring a baseline NMR spectrum of a pressure cell containing the sample, saturating the sample with a gas, acquiring a saturated NMR spectrum and determining a differential NMR spectrum of the sample by subtracting the baseline NMR spectrum from the saturated NMR spectrum. The method also includes separating the differential NMR spectrum into an absorbed gas NMR spectrum to determine an absorbed gas NMR signal and a pore gas NMR spectrum to determine a pore gas NMR signal by performing a spectral deconvolution. The method further includes acquiring a normalization NMR spectrum of the pressure cell containing a gas to determine a gas calibration NMR signal and determining the mass of the absorbed gas and pore gas.

Method to determine a mass of an absorbed gas and a mass of a pore gas in a sample

Techniques for determining a geologic property of a rock sample include (i) measuring a mass of a processed rock sample that includes a solid matrix and a fluid entrained within the solid matrix; (ii) measuring, using nuclear magnetic resonance (NMR), a volume of the fluid entrained within the solid matrix; (iii) measuring, using a gas porosimeter, a volume of the solid matrix of the processed rock sample; (iv) measuring, with a mercury immersion porosimeter, a bulk volume of the processed rock sample; and (v) determining, based at least on the measured volume of the fluid, the measured volume of the solid matrix, and the measured bulk volume, at least one of a bulk density, a grain density, or a porosity of the processed rock sample.

Determining geologic properties of a rock sample

A method and system for determining an uncorrupted NMR response from a sample at a predetermined measurement pressure is provided. The method includes obtaining a sample and a filler fluid with a negligible NMR response, determining a volume of filler fluid based on a dimension of the sample and an interior volume of a pressure cell, injecting the volume of filler fluid at a first temperature into the pressure cell and then changing the temperature of the volume of the filler fluid to a second temperature. The method also includes inserting the sample into the volume of filler fluid within the pressure cell, displacing an upper surface of filler fluid to a predetermined level within the interior volume of the pressure cell. The method still further includes establishing the predetermined measurement pressure within the pressure cell and determining the uncorrupted NMR response from the sample at the predetermined measurement pressure.

Method to determine an uncorrupted nuclear magnetic resonance response from a sample

A method for determining maximum recoverable hydrocarbon (EMR) in a tight reservoir is disclosed. The method includes determining, based on downhole logs, a total measure of hydrocarbon amount within the tight reservoir, determining, by at least attributing fluid loss during core surfacing of the core sample to hydrocarbons, a non-recoverable measure of hydrocarbon amount within a core sample of the tight reservoir, and determining an EMR measure based on the total measure of hydrocarbon amount and the non-recoverable measure of hydrocarbon amount, wherein during the core surfacing pore pressure reduces from a reservoir condition to a surface condition.

Determination of estimated maximum recoverable (EMR) hydrocarbons in unconventional reservoirs

Methods for predicting hydrocarbon production rates for a hydrocarbon reservoir include receiving data from a hydrocarbon reservoir. The data includes reservoir characterization data, well log data, and hydraulic fracturing data. A physics-constrained machine learning model predicts a hydrocarbon production rate for the hydrocarbon reservoir as a function of time. The physics-constrained machine learning model includes an artificial neural network and a hydrocarbon fluid flow model. Predicting the hydrocarbon production rate includes generating, by the artificial neural network, multiple parameters of the hydrocarbon fluid flow model based on the data from the hydrocarbon reservoir. The hydrocarbon fluid flow model provides the predicted hydrocarbon production rate as a function of time based on the parameters. A display device of the computer system presents the predicted hydrocarbon production rate for the hydrocarbon reservoir as a function of time.

Determination of hydrocarbon production rates for an unconventional hydrocarbon reservoir

A method for determining sweet spots in a subterranean formation includes drilling a plurality of wellbores in the subterranean formation using a drill tool; lowering a logging tool in each of the plurality of wellbores to collect measurements; calculating a reservoir quality index parameter for each wellbore of the plurality of wellbores based on petrophysical logs; creating a reservoir quality index map using the petrophysical logs; calculating a linear flow index parameter for each wellbore of the plurality of wellbores based on production data provided by the petrophysical logs; correlating the reservoir quality index parameter and the linear flow index parameter for each wellbore of the plurality of wellbores to locate sweet spots; and ranking a basin based on the located sweet spots and the correlated parameters.

Determining sweet spots and ranking of a basin

Techniques for determining grain density of a rock sample include identifying an untreated rock sample that includes a solid matrix and a fluid entrained within the solid matrix; measuring, using a gas porosimeter, a grain density of the untreated rock sample; measuring, using nuclear magnetic resonance (NMR), a volume of the fluid entrained within the solid matrix; and determining, based on the measured grain density of the untreated rock sample and the measured volume of the fluid, a grain density of the solid matrix of the untreated rock sample.

Systems and methods for determining grain density of an untreated rock sample using a gas porosimeter and nuclear magnetic resonance

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) 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.

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El Kennar, Algeria

Mohammed Boudjatit