Precise 3D Numerical Modeling of Fracture Flow Coupled With X-Ray Computed Tomography for Reservoir Core Samples

The present study focuses on the feasibility of a precise 3D numerical modeling coupled with X-ray computed tomography (CT), which enables simple analysis of heterogeneous fracture flows within reservoir core samples, as well as the measurement of porosity and permeability. A numerical modeling was developed and applied to two fractured granite core samples. One of the samples had an artificial single fracture (sample dimensions: 100 mm in diameter, 150 mm in length), and the other had natural multiple fractures (sample dimensions: 100 mm in diameter, 120 mm in length). A linear relationship between the CT value and the fracture aperture (fracture-aperture calibration curve) was obtained by X-ray CT scanning for a fracture-aperture calibration standard while varying the aperture from 0.1 to 0.5 mm. With the fracture-aperture calibration curve, 3D distributions of the CT value for the samples (voxel dimensions: 0.35x0.35x0.50 mm(3)) were converted into fracture-aperture distributions in order to obtain fracture models for these samples. The numerical porosities reproduced the experimental porosities within factors of approximately 1.3 and 1.1 for the single fracture and the multiple fractures, respectively. Using the fracture models, a single-phase flow simulation was also performed with a local cubic law-based fracture-flow model for steady-state laminar flow of a viscous and incompressible fluid. The numerically obtained permeabilities were larger than the experimentally obtained permeabilities by factors of approximately 2.2 and 2.7 for the single fracture and the multiple fractures, respectively. However, these discrepancies can be reduced to approximately 1.3-2.1 and 1.6-2.6, respectively, by simply using the correction factor for the cubic-law equation proposed by Witherspoon et al. (1980). Consequently, a precise numerical modeling coupled with X-ray CT is essentially feasible. Furthermore, the development of preferential flow paths (i.e., channeling flow) was clearly demonstrated for multiple fractures, which is much more challenging to achieve by most other methods. Further progress in modeling should enable the in-situ evaluation of heterogeneous fracture flow within reservoir core samples, as well as the clarification of the impacts of the heterogeneity on the productivity of wells and, for example, the efficiency of recovery by water-/gasflooding.