We present the results of a detailed experimental study in which underlying pore-level displacement physics of two- and three-phase flow in a fractured rock sample are investigated using high-resolution X-ray microtomography techniques. A unique, three-phase core-flooding setup integrated with a micro-CT scanner is used to conduct flow experiments on a miniature, partially fractured, sandstone sample using a brine/Soltrol 170 (spreading oil)/nitrogen and brine/decalin (nonspreading oil)/nitrogen fluid systems in order to shed light on subtle displacement mechanisms governing matrix-fracture interactions in the presence/absence of spreading oil layers.

The core sample, 10 mm in diameter and 40 mm in length, is first artificially fractured by applying non-uniform radial stress and then placed in a core holder under confining pressure. The net confining pressure is kept constant during all displacements to prevent changes in the fracture aperture. The fracture is purposely induced only in half of the length of the sample to allow the study of multiphase flow in both fractured and matrix-only portions. The fluid phases are injected into the medium from the fractured end. In the brine/Soltrol 170/nitrogen fluid system used, oil forms spreading layers sandwiched between brine and gas. Each experiment is initiated by fully saturating the core sample with brine. The initial two-phase condition prior to gas injection is subsequently established by primary oil drainage to Swi. Gas is then injected into the sample with different flow rates. When gas saturation in the fracture reaches to a certain level, it starts invading pore elements in the adjacent matrix displacing oil and brine into the fracture and/or toward the production through the matrix. Gas invades larger pore elements in the matrix and pushes oil into the fracture. When oil saturation in the spreading system reaches low values, the oil spreads between brine in the corners and gas in the center of the matrix pores and hence maintains its hydraulic connectivity through spreading layers with the oil in the fracture. This allows the oil in the matrix to drain into the fracture. The thickness and stability of these layers control the ultimate residual oil saturation and have significant impact on oil production from the matrix in fractured medium. In the nonspreading system, however, oil cannot maintain its connectivity due to the absence of stable spreading layers, resulting in higher residual oil saturation in the matrix and a lower ultimate recovery.

Accurate assessment of oil production schemes from complex fractured reservoirs has still remained a challenge in the oil industry. Mitigating uncertainty in such assessments and producing reliable recovery forecasts require a full understanding of fractured rock systems and the physics controlling matrix-fracture interactions in them. In this study, we employ high-resolution microtomography imaging techniques and miniature core-flooding methods to investigate pore-scale displacement mechanisms in the fracture and the matrix as well as matrix/fracture interactions under three-phase flow conditions.

You can access this article if you purchase or spend a download.