Mohsen Tagavifar

The dynamic behavior of microemulsion-forming water–oil–amphiphiles mixtures is investigated in a 2.5D micromodel. The equilibrium phase behavior of such mixtures is well-understood in terms of macroscopic phase transitions. However, what is less understood and where experimental data are lacking is the coupling between the phase change and the bulk flow. Herein, we study the flow of an aqueous surfactant solution–oil mixture in porous media and analyze the dependence of phase formation and spatial phase configurations on the bulk flow rate. We find that a microemulsion forms instantaneously as a boundary layer at the initial surface of contact between the surfactant solution and oil. The boundary layer is temporally continuous because of the imposed convection. In addition to the imposed flow, we observe spontaneous pulsed Marangoni flows that drag the microemulsion and surfactant solution into the oil stream, forming large (macro)emulsion droplets. The formation of the microemulsion phase at the interface distinguishes the situation from that of the more common Marangoni flow with only two phases present. Additionally, an emulsion forms via liquid–liquid nucleation or the Ouzo effect (i.e., spontaneous emulsification) at low flow rates and via mechanical mixing at high flow rates. With regard to multiphase flow, contrary to the common belief that the microemulsion is the wetting liquid, we observe that the minor oil phase wets the solid surface. We show that a layered flow pattern is formed because of the out-of-equilibrium phase behavior at high volumetric flow rates (order of 2 m/day) where advection is much faster than the diffusive interfacial mass transfer and transverse mixing, which promote equilibrium behavior. At lower flow rates (order of 30 cm/day), however, the dynamic and equilibrium phase behaviors are well-correlated. These results clearly show that the phase change influences the macroscale flow behavior.

This paper presents a new three-phase relative permeability model for use in chemical flooding simulators. Numerical simulation test cases are presented to illustrate the continuity of the new relative permeability model. Comparisons are made with a three-phase relative permeability model that has been widely used in chemical flooding simulators for decades. These comparisons show the old model has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters and requires less experimental data to determine the relative permeability parameters compared to the original model. Simulations using the new model showed excellent agreement with ASP coreflood data.

Summary: The rheological behavior of microemulsion systems was systematically investigated with mixtures of oil, brine, surfactant, cosolvent, and in some cases polymer to determine their effects. A microemulsion-rheology model was developed and used to interpret the experimental results. The optimal microemulsion/oil-viscosity ratio without cosolvent was roughly 5:6, but it can be reduced to a more favorable ratio of approximately 2 by adding cosolvent. Even though the amount of cosolvent needed is case dependent, a clear trend of microemulsion-viscosity reduction with increasing cosolvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide (HPAM) molecules with a narrow molecular-weight (MW) distribution have negligible partitioning to Type II and Type III microemulsions.

Summary: Primary and secondary oil recovery from naturally fractured oil-wet carbonate reservoirs is very low. Enhanced oil recovery (EOR) from these reservoirs by use of surfactants to alter the wettability and reduce the interfacial tension (IFT) has been extensively studied for many years, but there are still many questions regarding the process mechanisms, surfactant selection and testing, experimental design, and, most importantly, how to scale up the laboratory results to the field. Therefore, the primary objective of this study was to determine the effect of scale on the oil recovery from cores with different dimensions under low-IFT conditions. There was a particular need to perform experiments by use of cores with larger horizontal dimensions because nearly all previous experiments have been performed in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static-imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the produced emulsion. We used microemulsion-phase-behavior tests to develop surfactant formulations used in this study. These surfactants gave ultralow IFT at optimum salinity and good aqueous stability. Although we used ultralow-IFT (approximately 0.002 dynes/cm) formulations for most of the experiments, we also performed tests at low IFT (approximately 0.3 dynes/cm) for comparison. A second major objective of this study was to develop a simple analytical model to predict the oil recovery as a function of vertical- and horizontal-fracture spacing, rock properties, and fluid properties. The model and experimental data were found to be in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different from the traditional scaling groups in the literature. The model is useful for both interpreting the experiments and for scaling the results from the laboratory to the field.

Polymer flooding has been commercially applied to a number of viscous oil fields in the past decade and gradually gained more popularity. Due to limited injectivity in viscous-oil reservoirs, a relatively low polymer viscosity is usually used to avoid excessive injection pressure. In such a case, mobility ratio of polymer solution to oil is much greater than one, which implies unstable flow and strong viscous fingering. Existing reservoir simulators lack the capability of modeling such a physical phenomenon. Since many viscous-oil reservoirs have high permeability contrast between layers, we are motivated to study, for the first time, the impact of crossflow between different layers considering the presence of viscous fingering. Numerical modeling polymer floods with crossflow in a layered viscous-oil reservoir is difficult due to two major challenges: first is how to correctly allocate flow rates from the wellbore to multiple layers; and second is how to capture the viscous fingering effect without using excessively fine grids. To address the first issue, we developed an implicit well-rate-allocation model based on the potential method, which fully couples all the wellbore segments of each well with reservoir gridblocks to ensure a physical wellbore pressure. To deal with the second challenge, we implemented the effective fingering model, which is an upscaling model that lumps all the viscous fingers in a coarse grid block into one fictitious finger to allow for accurate estimation of fingering strength and growth during unstable flows. Both models were validated individually against the analytical solution or experimental data. The integrative module including the two new capabilities was used to simulate a polymer flood following a waterflood in a layer-cake reservoir in North America with moderate oil viscosity. We observed the fast propagation of water fronts and small fingering fraction in high permeability layers during the waterflooding phase, indicating active channeling and viscous fingering. The subsequent polymer flooding minimized both factors of oil bypassing and led to stable flow and high sweep efficiency. Without the implicit well-rate-allocation model, crossflow was overestimated and wellbore pressures of different well blocks were not consistent. Without the effective-fingering model, oil recovery was overestimated due to the lack of accounting for viscous fingering. The simulation results indicated that polymer flooding improved both displacement and sweep efficiencies. The model has shown comprehensive capabilities in reservoir simulations of polymer floods including unstable floods and crossflows between layers. This is a major significance to optimization of non-thermal viscous-oil EOR projects and also making more informed operational decisions for field developments.

We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.

Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.

The chemical cost to recover an incremental barrel of oil is directly proportional to the surfactant retention, so the single most effective way to reduce the cost is to reduce surfactant retention. The main objective of this research was to demonstrate how surfactant retention could be reduced to almost zero by careful optimization of the chemical formulations for different crude oils. Although surfactant retention has been studied for many years over a wide range of reservoir conditions, its dependence on the rheological behavior of the microemulsion that forms in-situ has not been adequately studied. Thus, in this paper we emphasize the importance of microemulsion rheology and demonstrate how to develop and test formulations with properties that give very low surfactant retention. Novel co-solvents (iso-butanol (IBA) alkoxylates and phenol alkoxylates) were tested in some of the formulations with excellent results. Unlike classical co-solvents used to optimize chemical formulations, the new co-solvents cause only a slight increase in the interfacial tension. A series of ASP corefloods were performed in sandstone cores with and without oil to measure surfactant and co-solvent retention and to elucidate the effects of microemulsion viscosity, salinity gradient, clay content, surfactant concentration and other variables. Dynamic adsorption was measured in cores with the same mineralogy and compared with the retention from oil recovery corefloods to determine the component of the retention due to phase trapping.