Preferential injection into high permeability thief zones or fractures can result in early breakthrough at production wells and large unswept areas of high oil saturation, which impact the economic life of a well. A variety of conformance control techniques, including polymer and silica gel treatments, have been designed to block flow through the swept zones. Over a certain range of salinities, silica nanoparticle suspensions form a gel in bulk phase behavior tests. These gels have potential for in situ flow diversion, but in situ flow tests are required to determine their applicability. To determine the appropriate scope of the in situ tests, it is necessary to obtain an accurate description of nanoparticle phase behavior and gel rheology. In this paper, the equilibrium phase behavior of silica nanoparticle solutions in the presence of sodium chloride (NaCl) is presented with four phase regions classified as a function of salinity and nanoparticle concentration. Once the gelation window was clearly defined, rheology experiments of silica nanoparticle gels were also carried out. Gelation time decreases exponentially as a function of silica concentration, salinity, and temperature. Following a power law behavior, the storage modulus, G 0 , increases with particle concentration. Steady shear measurements show that silica nanoparticle gels exhibit nonNewtonian, shear thinning behavior. This comprehensive study of the silica nanoparticle gels has provided a clear path forward for in situ tests to determine the gel's applicability for conformance control operations.

Viscous oil resources have great potential to help meet the future demand for petroleum products as conventional resources are depleted. Currently high temperature steam injection is the recovery process of choice, with high energy intensity and associated greenhouse gas emissions. The work presented here explores a low-temperature solvent-only injection strategy targeting fractured systems. The warm solvent is in the vapor phase when injected into the reservoir but will condense when it contacts the cold oil and reservoir rock (liquid extraction). After the system has reached the target operating temperature, the injected solvent remains in the vapor phase when it contacts the oil (solvent-enhanced gravity drainage). The experiments discussed in this work explore the key parameters (permeability, temperature/pressure, in situ injection rate, and solvent type) that influence each production mechanism. The primary impact of decreasing permeability is a proportional decrease in film gravity drainage rate. A decrease in temperature slows the mass transfer during the liquid extraction phase and decreases the drainage rate during the film gravity drainage phase. Increasing the in situ injection rate leads to improved liquid extraction because of higher concentration gradient in the solvent-rich liquid phase at the oil/solvent interface. Solvent type affects both mechanisms and changes the nature and amount of asphaltene precipitation. Pentane yields relatively less asphaltene precipitate than butane (18 wt % vs 11 wt % asphaltene content in residual oil). Residual oil saturation was observed to increase as permeability and/or temperature were decreased.

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