No abstract

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.

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.

During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Measuring and modeling relative permeability as compositional regions are traversed creates many challenges. In simulators, the association of each phase with a relative permeability curve sometimes creates discontinuities when phases disappear across miscibility boundaries. Some newer relative permeability models attempt to resolve these issues by changing the standard "oil" and "gas" method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE). Ideally, a relative permeability model will be based on experimental measurements. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary numbers were kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to form droplets, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that the oil phase connectivity is more important than compositional parameters.