RESUMEN
The in situ change in oil flow behavior inside propped fractures due to wettability alteration of proppant grains and fracture surfaces was thoroughly investigated for the first time in this study. A series of microscale flow experiments were performed in mixed-wet fractured and propped miniature ultra-tight carbonate cores where the effect of wettability on oil bridging and fracture oil layer integrity was probed during oil production. During the initial production, proppant wettability changed toward an intermediate-wet state (contact angle (CA) = 96°) while that of fracture surfaces became strongly oil-wet (CA = 139°). Consequently, the fracture oil layer grew in size on both fracture surfaces and imbibed into the proppant pack through piston-like displacement and pore body filling until oil bridges were formed during oil injection. However, subsequent waterflooding induced thinning and rupturing of those bridges due to the accompanying reduction in the threshold capillary pressure of the proppant at higher aging times. The in situ chemical treatment of the proppant by a cationic surfactant (dodecyl tri-methyl ammonium bromide) could reverse its wettability toward weakly water-wet state (CA = 78°) after oil solubilization from the sand grains followed by substitutive surfactant adsorption. Surfactant injection also impacted the wettability of the fracture surface due to oil solubilization, reducing its mean contact angle down to an intermediate range (CA = 99°). As a result, the following oil production cycle yielded a smaller fracture oil layer. The surfactant effect on proppant wettability lasted for 2 weeks while its effect on fracture wettability lasted for more than 6 weeks. Similar flow cycles were performed with an anionic nanoparticle (graphene quantum dot) with hydrogen bonding ability. The nanoparticle solution yielded a quick reduction of the proppant and fracture surface contact angles to nearly 77° and 115°, respectively. Proppant wettability alteration occurred because the nanoparticles self-assembled at the three-point contact region between adsorbed oil and quartz surfaces, leading to oil solubilization in intermediate-wet regions while oil-wet regions remained unchanged. Therefore, re-introducing oil into the fracture instantaneously re-instated the initial wettability state of proppant grains (CA = 88°), deeming the nanoparticle solution ineffective. This study revealed that oil production through hydraulic fractures can be enhanced by monitoring the wettability of the proppant pack. If the production has a high water cut, it is beneficial to use chemical agents that reduce the proppant contact angles to a weakly water-wet state in order to preserve the hydraulic conductivity of the oil layer.
RESUMEN
Subsurface formations often contain multiple minerals with different wettability characteristics upon contact with nonaqueous-phase liquids (NAPLs). Constitutive relationships between microstructure heterogeneity and NAPL fate and transport in these formations are difficult to predict. Several studies have used pore-scale network models with faithful representations of rock pore space topology to predict macroscopic descriptors of two-phase flow, however wettability is usually considered as a spatially random variable. This study attempts to overcome this limitation by considering more realistic representations of rock mineralogy and wettability in these models. This is especially important for heterogeneous rocks where properties vary at the pore-scale. The work was carried out in two phases. First, pore-fluid occupancy maps during waterflooding were obtained by X-ray microtomography to elucidate the impact of pore wall mineralogy and wettability on water preferential flow paths and NAPL trapping within a heterogeneous aquifer sandstone (Arkose). Then, microtomography images of the rock were used to generate a hybrid pore network model (PNM) that incorporated both pore space topology and pore wall mineralogy. In-situ contact angles (CA) measured on the surface of different minerals were assigned to the network on a pore-by-pore basis to describe the exact wettability distribution of the rock (Pore-by-pore model). The equivalent network was used as input in a quasi-static flow model to simulate waterflooding, and the predictions of residual NAPL saturation and relative permeabilities were compared against their experimental counterparts. To examine the sensitivity of the model to the underlying fluid-solid interactions, we also used traditional methods of wettability characterization in the input data and assigned them randomly to the PNM. Wettability in this case was assessed from macroscale CA distribution of oil droplets on the surface of unpolished Arkose substrates released by spontaneous imbibition of water (Arkose model) and from pendant drop measurements on polished quartz (Quartz model). Our results revealed that the Pore-by-pore model predicted waterflooding with the highest accuracy among all three cases. The Arkose model slightly overestimated NAPL removal whereas the Quartz model failed to predict the experiments. More in-depth analysis of the Pore-by-pore and Arkose models showed that macroscopic transport quantities are less dependent to microstructure heterogeneity if minerals are distributed uniformly across the rock. The predictions herein indicate the importance of incorporating mineralogy and wettability maps to improve the prediction capabilities of PNMs especially in systems with high mineral heterogeneity, where minerals are nonuniformly distributed, or selective fluid-mineral interactions are targeted.