Saudi Arabian Oil Company

King Abdullah University of Science and Technology

King Fahd University of Petroleum and Minerals

Hyung Tae Kwak

Ahmad Mubarak Al-Harbi

Jun Gao

Marwah Mufid AlSinan

Abdulaziz S Al-Qasim

Salah Hamad Al-Saleh

Xupeng He

Hussein Ali Hoteit

Ali Abdullah Al-Yousif

Ahmad Mubarak Alharbi

Mohamed Mahmoud

Dong Kyu Cha

Muhammad Majid Almajid

Mahmoud Elsayed

Ammar El-Husseiny

Moataz Abu AlSaud

Ali Abdullah Al-Yousef

Atul Godbole

Ali AlYousef

Mohammed Abbad

Tareq Ghamdi

Yiteng Li

Naif J Alqahtani

Zuhair A Yousif

Mustafa R Satrawi

Hussein Hoteit

Ali A Al-Yousif

Described is a method for evaluating oil recovery. The method includes performing a pre-coreflood process, a coreflood process, and a post-coreflood process. The pre-coreflood process includes preparing heterogenous cores samples with different structural configurations. The coreflood process includes injecting a treatment into the core samples and obtaining nuclear magnetic resonance (NMR) measurements of the treated core samples. NMR measurements are compared to assess performance of the treatment. The post-coreflood process includes conducting an X-ray micro-computerized topography (CT) scan and a Saturate, Aromatic, Resin, and Asphaltene (SARA) analysis on the treated core samples.

Method for evaluating advanced conformance control, sweep efficiency, deep diversion, and water shutoff treatments

Systems and methods for determining a 3D hydraulic aperture of a 3D fracture are disclosed. The method includes, obtaining a geometry of the 3D fracture, determining a fluid flow direction through the 3D fracture, and dividing the 3D fracture into a plurality of 2D cross-sections oriented substantially parallel to the fluid flow direction. The method further includes dividing each 2D cross-section into a plurality of Type I and Type II fracture segments based on a segment aspect ratio and a segment roughness ratio, determining a 2D segment hydraulic aperture for each of the plurality of Type I and Type II fracture segments, and determining the 3D hydraulic aperture of the 3D fracture based, at least in part, on the 2D segment hydraulic apertures of the plurality of Type I and Type II fracture segments.

Method to calculate the effective hydraulic aperture and permeability of rock fractures

A method and system for labeling and identifying a sample, including a rock core sample, after determining a physical primary label has been compromised is provided. The method includes labeling the sample by placing a physical primary label on the sample or sample container, creating a first rollout image of the sample for a secondary label, and storing the first rollout image in a secondary label digital database with a sample identifier. The method continues for identifying the sample after determining the physical primary label has been compromised by creating a secondary rollout image of the sample and searching the secondary label digital database using the second rollout image to create a plurality of matching scores using a machine learning or deep learning image matching technique. The matching scores are then evaluated to determine an identify of a sample and the sample is re-labelled using a replacement primary label.

Sample labeling method using image-matching

Hydrocarbon extraction may be coupled with subterranean hydrogen storage. For example, a method of hydrocarbon extraction and hydrogen storage may include: introducing carbon dioxide into a subterranean formation via one or more injection wells, the subterranean formation containing hydrocarbons and optionally water; mobilizing at least a portion of the hydrocarbons in a hydrocarbon-bearing zone of the subterranean formation with the carbon dioxide; after mobilization with the carbon dioxide, producing the hydrocarbons from the hydrocarbon-bearing zone of the subterranean formation via one or more production wells; introducing hydrogen to the subterranean formation via the one or more injection wells, the hydrogen displacing the carbon dioxide downward in the subterranean formation; storing the hydrogen in the subterranean formation above the carbon dioxide; and producing at least a portion of the hydrogen from the subterranean formation via the one or more production wells, the one or more injection wells, or any combination thereof.

Carbon dioxide enhanced hydrocarbon recovery methods coupled with underground hydrogen storage

A method may include obtaining fracture image data regarding a geological region of interest. The method may further include determining various fractures in the fracture image data using a first artificial neural network and a pixel-searching process. The method may further include determining a fracture model using the fractures, a second artificial neural network, and borehole image data. The method may further include determining various fracture permeability values using the fracture model and a third artificial neural network. The method may further include determining various matrix permeability values for the geological region of interest using core sample data. The method may further include generating a coarsened grid model for the geological region of interest using a fourth artificial neural network, the matrix permeability values, and the fracture permeability values.

Method and system for determining coarsened grid models using machine-learning models and fracture models

Techniques for determining reservoir formation properties include generating digital models of core samples taken from one or more reservoir formations based on corresponding images of the core samples; determining a pore throat size distribution of the core samples based on the generated digital models; determining corresponding capillary pressure curves and corresponding NMR value distributions of the core samples with one or more numerical simulations; generating one or more machine-learning (ML) models based on the pore throat size distribution, corresponding capillary pressure curves, and corresponding NMR value distributions of the core samples; adjusting the one or more ML models with one or more reservoir data of the one or more reservoir formations; generating adjusted capillary pressure curves and NMR value distributions from the one or more adjusted ML models; and determining a reservoir formation specific pore throat size distribution from at least one of the adjusted capillary pressure curves or the adjusted NMR value distributions.

Determining reservoir formation properties

A method includes providing an injection well extending from a surface into a formation and alternatingly pumping a foam injectant and a gel injectant into the injection well, wherein the foam injectant includes a liquid phase with a surfactant and water and a gas phase and the gel injectant includes a water-soluble polymer and a crosslinker. The foam injectant and the gel injectant are injected at separate times and sequentially.

Methods for foam and gel injections into a well and enhanced foaming and gelations techniques

A method for determining the pore size distribution in a reservoir, including the steps: drilling a core sample out of the reservoir, determining a porosity distribution along the core sample, obtaining T-distributions at different saturation levels of the core sample with formation brine, performing time domain subtraction on the T-distributions to obtain T-distributions at all saturation levels, determining the pore throat size distribution along the core sample, determining first porosities from the T-distributions that correspond to second porosities of the pore throat size distribution for each saturation level, determining T-distributions at the first porosities from the T-distributions, determining pore throat sizes at the second porosities from the pore throat size distributions, plotting the pore throat sizes as function of the relaxation times Tto obtain the surface relaxation, and determining the pore size distribution of the reservoir.

Method for determining the pore size distribution in a reservoir

A method includes deriving spatial permeability along a core axis by saturating the rock with an aqueous solution, performing TNMR on the saturated rock to detect spatial NMR data along the core axis, desaturating the rock, performing TNMR on the desaturated rock to detect spatial NMR data along the core axis, determining the spatial cutoff data for the saturated and desaturated rock along the core axis, and analyzing the spatial NMR data. The method further includes deriving spatial permeability along a second core axis by additionally performing TNMR on the saturated rock to detect spatial NMR data along a second core axis, performing TNMR on the desaturated rock to detect spatial NMR data along a second core axis, and determining the spatial cutoff data for the saturated and desaturated rock along the second core axis.

Method for measuring the spatial water permeability profile of porous media by using non-destructive nuclear magnetic resonance technique

A method may include obtaining first nuclear magnetic resonance (NMR) data for a saturated core sample regarding a geological region of interest. The method may further include determining, using the first NMR data, spatial porosity data based on the saturated core sample. The spatial porosity data may describe various porosity values as a function of a sampling position of the saturated core sample. The method may further include obtaining second NMR data for a desaturated core sample regarding the geological region of interest. The method may further include determining, using the second NMR data, spatial permeability data based on the desaturated core sample. The method may further include determining a geological model for the geological region of interest using the spatial porosity data, the spatial permeability data, and a fitting process.

Method and system for determining geological models using spatial properties based on nuclear magnetic resonance data

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 Tdistribution 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 Tdistribution 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 Tdistributions.

Determining saturation in low resistivity pay zones

A method includes screening heterogeneity of a rock sample using nuclear magnetic resonance testing to determine a composition of the rock sample, drilling at least one smaller rock sample representative of the determined composition, and testing the at least one smaller rock sample with mercury injection capillary pressure to obtain a capillary pressure distribution of the at least one smaller rock sample. The method further includes decomposing a Tdistribution from the nuclear magnetic resonance testing and the capillary pressure distribution using Gaussian fitting to identify multiple pore systems, where the small ends of the Gaussian fitted Tdistribution and the Gaussian fitted capillary pressure distribution are overlapped for at least one of the identified pore systems.

Combined discrete gaussian analysis of MICP and NMR T2 distributions of multi-modal carbonate rocks

A nuclear magnetic resonance (NMR) logging system and method is disclosed. The method may include obtaining an NMR well log, a measured downhole temperature, and at least one rock sample for a formation in a subsurface region. The method may further include determining an NMR distribution for each sample and selecting a set of samples based on the determined NMR distribution. For each selected sample, the method may further include determining a first parameter of the NMR distribution, a regression parameter of a relationship, and a first and second fractal parameters of the NMR distribution. The method may further include determining a second parameter of the NMR distribution based on the first and second fractal parameters, the regression parameter, and the downhole temperature. The method may still further include determining a parameter of the formation based on the second parameter of the NMR distributions of the set of samples.

Method and system using nuclear magnetic resonance well logging for Tcutoff value estimation

A method for determining pore size distribution of rocks is provided. Capillary pressure measurements on rock cores are analyzed to determine a pore size distribution, with smaller pores requiring greater capillary pressure to relinquish contained fluid. Large pores with rough surfaces introduce inaccuracies in determining the pore size distribution. Embodiments of the invention correct the rough surface induced inaccuracies by measuring the shift in NMR T2 distribution from full saturation to the current state of desaturation and subtracting the T2 contributions in the desaturated state that have smaller T2 values (i.e., smaller transverse relaxation time) than the smallest T2 values (i.e., shortest transverse relaxation time) in the saturated distribution.

Method to determine pore size distribution of rocks with rough surface from capillary pressure by nuclear magnetic resonance

A fracture geometry mapping method includes determining a value of a diffusive tortuosity in a first direction in a first rock sample from a subterranean formation with one or more hardware processors; determining a value of a diffusive tortuosity in a second direction in the first rock sample from the subterranean formation with the one or more hardware processors, the second direction orthogonal to the first direction in the first rock sample; determining a value of a diffusive tortuosity in third direction in the first rock sample from the subterranean formation with the one or more hardware processors, the third direction orthogonal to both the first direction and the second direction in the first rock sample; comparing the values of the diffusive tortuosities in the in the first direction, the second direction, and the third direction; and based on the comparison, generating a first fracture network map of the subterranean formation, the first fracture network map including a first plurality of anisotropic fracture pathways.

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Dhahran, Saudi Arabia

Hyung Tae Kwak