Summary
Image-based computations of relative permeability require a description of fluid distributions in the pore space. Recent advances in imaging technologies have made it possible to directly resolve actual fluid distributions at the pore scale, thus capturing a large field of view for arbitrary wetting conditions, which are numerically difficult to reproduce. In previous studies, fluid distributions were not imaged under in-situ conditions, which may cause the oil (nonwetting) phase to snap off. Consequently, computed oil relative permeability is underestimated, particularly at low oil saturations. This study extends our previous work by imaging fluid distributions under in-situ conditions as a basis for numerical computations.
In this study, we perform a steady-state flow test on a homogeneous outcrop sandstone (Bentheimer) core. First, the dry core is imaged in our microcomputed-chromatography (micro-CT) facility. Afterward, the core is fully saturated with 0.4 molar sodium iodide (NaI) solutions. The saturated core is then mounted in a specially designed flow cell that allows the flow experiment to be performed with the core mounted on the CT scanner. Afterward, a steady-state injection of oil and brine is performed at four different oil/water-injection ratios. For each injection ratio, steady-state pressure drop is noted, and in-situ fluid distributions are imaged under flow conditions. These imaged fluid distributions are used to compute image-based relative permeability, whereas the measured pressure drops are used to calculate experimental relative permeability.
Results demonstrate that imaging in-situ fluid distributions allows us to overcome significant limitations of our previous work: Namely, measured and computed oil relative permeability are in close agreement across the whole saturation range, and laboratory capillary end effects at the core outlet can be imaged, which allows us to apply a correction to the laboratory-measured data.
