Reports: DNI951616-DNI9: Measuring the Impact of Nanoscale Features on Oil and Gas Recovery

Keith B. Neeves, PhD, Colorado School of Mines

ACS 2013 Narrative Report

The scientific objective of this proposal is to conduct a fundamental study on the impact of nanoscale features on fluid flow and transport. Specifically, we are measuring how nanoscale features affect fluid and solute transport in dual porosity and random media.  Our approach uses nanofabricated porous media models to measure and visualize single phase and multiphase transport. The dispersion of tracers within these models will be interpreted using the formalism of macrotransport theory to gain insight into the mechanisms of solute exchange between microscale and nanoscale pores.  The proposed research is significant because until we understand transport mechanism in multiphase flows between microscale fractures and nanoscale matrices, we cannot develop extraction strategies to recover resources in these features.

            In Year 2 of the project, we have used the nanofabricated porous media models developed in Year 1 to make measurements of fluid and solute transport. Using oil-wet polydimethylsiloxane (PDMS) microfluidic porous media analogs, we studied the effect of pore geometry and interfacial tension on water-oil displacement efficiency driven by a constant pressure gradient (Figure 1). This situation is relevant to the drainage of oil from a bypassed oil-wet zone during water flooding in a heterogeneous formation. The porosity and permeability of analogs are 0.19 and 0.133 – 0.268 × 10-12 m2, respectively; each analog is 30 mm in length and 3 mm in width, with the longer dimension aligned with the flow direction. The pore geometries include three random networks based on Voronoi diagrams and eight periodic networks of triangles, squares, diamonds, and hexagons. We found that among random networks both pore size distribution and vugs (large cavities) decreased the displacement efficiency, among the periodic networks the displacement efficiency decreased with increasing coordination number, and the random network with uniform microfluidic channel width is similar to the hexagon network in the displacement efficiency. When vugs are present, the penetration was controlled by the sequence of vug-filling and the structure of inter-vug texture was less relevant. Surfactant (0.5 wt. % ethoxylated alcohol) increased the displacement efficiency in all geometries by increasing the capillary number and suppressing the capillary instability. The velocity of the water-oil front decreased with increasing penetration and eventually the front split into capillary fingers. By fitting the process to the Washburn equation we estimated the instantaneous capillary numbers just prior to the onset of fingers, and they are about 10-8 for water flooding, and 10-7 for surfactant flooding. This work has been submitted for publication and is currently under review.

            Using silicon-quartz nanofluidic devices we have studied gas-liquid flows in nanochannels with dimensions that match that of tight sand and shale (Figure 2). These formations exist in underground reservoirs with microdarcy (µD) or even nanodarcy permeability ranges and are characterized by small pore throats and crack-like interconnections between pores. The size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid flow behavior in the nano-range channels is of major importance for both stimulation design, gas production optimization and calculations of the relative permeability of gas in tight shale gas systems. Direct visualization of the fluid flow behavior in nanochannels was developed using an advanced single-molecule imaging system combined with nanofluidic devices. Under experimental conditions, the gas slippage factor increased as the water saturation increased. It was found that there was over 40% of remaining water saturation after gas displacing water while only less than 10% of gas remaining saturation in water displacing gas experiments. Under experimental conditions, the gas slippage factor increased with increases of remaining water saturation, possibly because the increase in water saturation dramatically reduced the effective radius of the gas channel. Based on Klinkenberg's theory, the gas slippage factor increases as the channel radius decreases, which was proved by the two-phase flow imaging data. The correlation between absolute gas permeability and the two phase gas slip factor was studied and the empirical correlation between two phase gas slip factor and absolute permeability was derived. The results of two-phase fluid flow and residual gas/water saturations in channels and nanochannels are very valuable for achieving a better understanding of gas flow behavior in shale and determining relative permeability in unconventional tight gas plays. This work has been submitted for publication and is currently under review.