Li, Yuxiang (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Churchwell, Lauren (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
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.
Sharma, Himanshu (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Recent studies on the use of ammonia as an alkali for performing alkali-surfactant-polymer (ASP) floods have shed light on its advantages over conventional alkalis such as lower alkali requirements, ease of transportation and storage. This study is aimed towards understanding surfactant adsorption in sandstone and carbonate rocks in the presence of ammonia. Zeta potential measurements were performed to characterize Bandera brown sandstone and Silurian dolomite surfaces in the presence of ammonia and sodium carbonate. A series of experiments were performed with and without ammonia such as static surfactant adsorption experiments on crushed Bandera brown sandstone and Silurian dolomite rocks, single phase surfactant transport experiments in sandstone and carbonate cores, surfactant phase behavior to identify an ultra-low interfacial tension (IFT) surfactant formulation, and oil recovery coreflood experiments using these surfactant formulations. Zeta potential measurements showed a reduction in zeta potential of Bandera brown and Silurian dolomite by adding ammonia to increase the pH. Surfactant adsorption experiments showed that ammonia was able to reduce the adsorption on sandstones, but not much difference was observed for carbonates. The ultra-low IFT surfactant formulations developed with and without ammonia showed very similar phase behavior. High oil recoveries and very low surfactant retentions were observed in the oil recovery experiments performed in sandstones.
A. Nadeeka Upamali, Karasinghe (The University of Texas at Austin) | Liyanage, Pathma Jith (The University of Texas at Austin) | Cai, Jiajia (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Jang, Sung Hyun (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
The ability to develop high performance, low cost chemical formulations for chemical EOR involves the use of not only highly efficient surfactants tailored to specific crude oil and reservoir conditions, but also the technical know-how for combining the surfactants and other chemicals to create the best formulation as a complete package. Scientific understanding of how the molecular structures of surfactants and co-solvents affect microemulsion properties greatly speeds up the process of arriving at optimal formulations for enhanced recovery of a specific crude oil in a specific oil reservoir. With the main emphasis on reducing the chemical cost of the formulations, a new slate of novel chemicals, both surfactants and co-solvents, has been developed and shown to have superior performance. We have synthesized and tested new classes of surfactants with different hydrophobe sizes and structures varying from large-medium-short-ultrashort in order to meet the needs of a variety of crude oil requirements. We have also developed ultra-short hydrophobe surfactants (with 2-ethylhexanol hydrophobe) possessing dual surfactant / co-solvent properties. Such duality in performance helps, in some cases, to minimize or altogether offset the use of co-solvents while maintaining low microemulsion viscosities, faster equilibration, and other desirable behavior. Thus, 2-ethylhexanol-propoxy-sulfate was developed as a surfactant that also encompasses co-solvent properties. The novel Gemini surfactants have also been incorporated in formulations and core flood experiments with excellent results. The new co-solvents offer advantages such as short equilibration time for the microemulsion formation and lower microemulsion viscosity. Systematic studies using these new surfactants and co-solvents clearly show that we now have the capability of developing highly robust formulations to meet the needs of a variety of reservoirs, resulting in high oil recoveries with low surfactant retention, which is the key to lowering the chemical costs and improving the economics of chemical enhanced oil recovery.