An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI

CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.

Transport Behavior of Liquid Hydrocarbon in Shale Matrix with Mixed Wettability Nanopores

Shale oil is an unconventional petroleum resource which has high total organic carbon (TOC) content and abundant nanopores. The transport behavior of oil through organic rich shales cannot be described by the classical Darcy law due to its complex pore structure and the complicated distribution of organic matter, which results in nanoconfined effects. In this work, on the basis of the boundary slip phenomenon and the fractal scaling theory, a model for oil transport in shale matrix is established considering nanoconfined effects and adsorbed organic matter. The results show that it is necessary to make correction of viscosity and the boundary slip length in order to accurately describe the flow behavior of oil in shale matrix with mixed wettability nanopores. Long chain molecules are more sensitive to nanoconfined effects, especially when adsorbed organic matter is considered. Also, the oil transport capacity in organic shale matrix is greatly enhanced compared to the classical no-slip permeability model. Meanwhile is the oil transport capacity is significantly reduced in inorganic shale matrix. This work shows that the identification of higher TOC region and considering the nanoconfined effects are necessary from the concept of oil transport in shale matrix.

Rheology of Immiscible Two-phase Flow in Mixed Wet Porous Media: Dynamic Pore Network Model and Capillary Fiber Bundle Model Results

Immiscible two-phase flow in porous media with mixed wet conditions was examined using a capillary fiber bundle model, which is analytically solvable, and a dynamic pore network model. The mixed wettability was implemented in the models by allowing each tube or link to have a different wetting angle chosen randomly from a given distribution. Both models showed that mixed wettability can have significant influence on the rheology in terms of the dependence of the global volumetric flow rate on the global pressure drop. In the capillary fiber bundle model, for small pressure drops when only a small fraction of the tubes were open, it was found that the volumetric flow rate depended on the excess pressure drop as a power law with an exponent equal to 3/2 or 2 depending on the minimum pressure drop necessary for flow. When all the tubes were open due to a high pressure drop, the volumetric flow rate depended linearly on the pressure drop, independent of the wettability. In the transition region in between where most of the tubes opened, the volumetric flow depended more sensitively on the wetting angle distribution function and was in general not a simple power law. The dynamic pore network model results also showed a linear dependence of the flow rate on the pressure drop when the pressure drop is large. However, out of this limit the dynamic pore network model demonstrated a more complicated behavior that depended on the mixed wettability condition and the saturation. In particular, the exponent relating volumetric flow rate to the excess pressure drop could take on values anywhere between 1.0 and 1.8. The values of the exponent were highest for saturations approaching 0.5, also, the exponent generally increased when the difference in wettability of the two fluids were larger and when this difference was present for a larger fraction of the porous network.