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Summary Reservoir studies involve spatial scales ranging from pore models to field-simulation grids. X-ray tomography is a nondestructive technique of inspection and characterization of samples that works from microns in the pore scale to centimeters in drill cores, which makes it a useful tool for modeling porous systems in reservoir-rock samples. The generated models serve to simulate physical phenomena helpful to determine both static and dynamic properties. Various techniques of preprocessing, porous-medium modeling, and simulation are applicable depending on the degree of heterogeneity of the sample. This work presents a workflow to make the porosity and permeability models from images acquired with axial computed tomography (CT) at different resolution scales. The workflow was used in sandstone and carbonate samples from Brazilian outcrops. The density and porosity of the sample were determined at the millimeter scale using a medical scanner and the distributions of pore size, grain size, and absolute permeability were determined using a synchrotron beamline, which provided high-resolution data at the micrometer scale. Integrating the data obtained from both scales, the combined description of the drill-core porosity served as a base to build a permeability model for the sample with the dimensions of that one scanned by the medical CT. The approach to generate the model depends on the type of heterogeneities associated with the sample. The homogeneous sandstone sample was modeled as a matrix with undefined porosity at the resolution of the medical tomography. The carbonate sample showed defined porosity at different scales: Moldic and vugular porosity were defined on the medical scale, while interparticle porosity was set on the synchrotron scale. Permeability was simulated in the micrometric model using an approach that integrates Stokes law and Darcy’s law in a percolating porous medium. Subsequently, the permeability was transferred to the millimetric model, creating the 3D distribution of porosity and permeability. Finally, the upscaled value for the samples was determined. This study contributes to the approaches regarding techniques of rock upscaling and digital rock physics and presents a workflow and some discussions of the multiscale approach.
- North America > United States (1.00)
- South America > Brazil (0.68)
- Asia > Middle East > Saudi Arabia (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Simultaneous Neutron and X-Ray Imaging of 3D Kerogen and Fracture Structure in Shales
Chiang, Wei-Shan (Aramco Research Center-Houston/ National Institute of Standards and Technology/University of Delaware) | LaManna, Jacob M. (National Institute of Standards and Technology) | Hussey, Daniel S. (National Institute of Standards and Technology) | Jacobson, David L. (National Institute of Standards and Technology) | Liu, Yun (National Institute of Standards and Technology/University of Delaware) | Zhang, Jilin (Aramco Research Center-Houston) | Georgi, Daniel T. (Aramco Research Center-Houston) | Chen, Jin-Hong (Aramco Research Center-Houston)
ABSTRACT Hydrocarbon production from shales using horizontal drilling and hydraulic fracturing has been the key development in the US energy industry in the past decade and has now become more important globally. Nevertheless, many fundamental problems related to the storage and flow of light hydrocarbons in shales are still unknown. It has been reported that the hydrocarbons in the shale rocks are predominantly stored within the kerogen pores with characteristic length scale between 1 nm to 100 nm. In addition, the 3D connectivity of these kerogen pores and fractures from the micrometer to centimeter scale form the flow path for light hydrocarbons. Therefore, to better model the gas-in-place and permeability in shales, it is necessary to quantify the structural distribution of organic and inorganic components and fractures over a large breadth of length scales. Simultaneous neutron and X-ray tomography offers a core-scale non-destructive method that can distinguish the organic matter, inorganic minerals, and open and healed fractures in 2.5 cm diameter shales with resolution of about 30 μm and field of view of about 3 cm. In the reconstructed neutron volume, the hydrogen-rich areas, i.e. organic matter, are brighter because hydrogen has a larger attenuation coefficient and attenuates neutron intensity more significantly. For the X-ray volume, the attenuation coefficient of an element is related to its atomic number Z and the brighter areas indicate the region containing more high-Z elements such as minerals. Open fractures do not attenuate either neutrons or X-rays and therefore look dark in both reconstructed neutron and X-ray volumes. In this study, two shale samples from different locations were investigated using simultaneous neutron and X-ray tomography for the first time. We were able to construct 3D images of shales and isolate 3D maps of organic matter and high-Z minerals. The distribution of kerogen and fractures can be used in the modeling of hydrocarbon flow in core scale, a 109 upscaling from current methods that model the flow based on SEM images.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.94)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.89)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (0.76)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.66)
Summary 3D electrical-impedance tomography (EIT) is a technique that has the potential to provide estimates of reservoir saturation at multiple scales by determining the resistivity distribution within the subsurface. In theory, EIT is well suited for researching oil and brine systems because of the large contrast in resistivity between the two phases. Here, in our initial laboratory investigation, we have applied the EIT technique to measure the saturation distribution of water within a core. The initial EIT experiment presented here used a Berea-sandstone core with 48 electrodes attached in three rings of 16. The core was open to the atmosphere, with saturation occurring by natural imbibition and desaturation occurring by evaporation. The voltage-potential field was measured by applying a direct-current (DC) pulse across the core and measuring the voltage potential at all electrodes, essentially applying the four-wire resistance technique over all electrodes in turn. The result was a data set that embodies the resistivity distribution within the core, and, by inversion, the resistivity distribution was reconstructed, which allowed for the inference of the saturation. The data processing was accomplished by using the Electrical Impedance Tomography and Diffuse Optical Tomography Reconstruction Software (EIDORS) toolkit, which was developed for application to this nonlinear and ill-posed inverse problem. The procedure uses a finite-element model for forward calculation and a regularized nonlinear inverse solver to obtain a unique and stable inverse solution. Experiments have indicated that EIT is a viable technique for studying the displacement characteristics of fluids with contrasting resistivity and is capable of detecting displacement fronts in near to real time. The current system is also a quantitative technique able to measure saturation distributions accurately between 15% < Sw < 65% in a Berea sandstone core. These limitations were imposed because of connate-water connections to the electrodes and ion-mobility effects caused by the DC voltage source. It is anticipated that the applicability of EIT will increase with the implementation of an alternating-current (AC) voltage source. Introduction In an oil reservoir, it is crucial to know the extent, the saturation distribution, and the connectivity of the resource. The extent is typically well understood compared to the connectivity and saturation distribution within the reservoir. At the field scale, where the question of connectivity between wells is of critical importance, injection- and production-history data may be used to infer connectivity. However, the productivity of a field may be placed in jeopardy by improper placement of an injection well. Therefore, knowing the connectivity of the reservoir early in development would help minimize risk and maximize productivity throughout the life of a reservoir. For this reason, EIT at the field scale is of particular interest in identifying connective faults and fractures throughout the reservoir. However, before any large-scale investigations may be pursued with EIT, a laboratory-scale EIT system has been developed to investigate core-scale fluid interactions that are of equal importance to the life of a reservoir. Core experiments may infer the microscale properties that influence the life of the reservoir significantly—primary and secondary porosity and permeability, relative permeability in fractures, and saturation distribution. In laboratory experiments, ferrous core holders are often used to replicate high reservoir pressures and temperatures. However, the use of a ferrous core holder eliminates the application of the X-ray computed-tomography (CT) -scan technique to estimate in-place saturations because the X-rays cannot penetrate the steel vessels. Consequently, because of the importance of understanding core-scale phenomenon and the limitations of the X-ray CT scan, EIT has been investigated as a new technique to image fluid distribution.
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Research Report (0.46)
- Overview > Innovation (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Geology > Geological Subdiscipline (0.34)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
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