Flow Physics of Profile Control Fluids in Porous Media and Implications for Enhanced Oil Recovery: A Microfluidic Study

Novel profile control agents are constantly emerging in the field of enhanced oil recovery, contributing to the extension of a stable production period. However, evaluation performed through conventional core flow experiments is usually inadequate to reveal the in-depth mechanism of profile control agents. Besides, due to different operation and production modes, there is an urgent need for a specific experimental method applicable to horizontal wells in bottom water reservoirs. In this context, this paper describes two models tailored to bottom water reservoirs and investigates the flow characteristics and mechanisms of three water-shutoff agent types. At the pore scale, further study was carried out on the water-shutoff synergism between a gel and an emulsifier. The results show that the gel is present at the edge of the pore body, while the emulsion is blocked in the center of the pore body. Hence, gel that enters a water channel (main flow and accumulation area of emulsion) can cooperate with an emulsion to achieve high-strength water shutoff, making the bottom water that re-invades mainly break through at oil-rich areas. Compared with water shutoff with gel alone (randomly distributed in the breakthrough area), the synergism improves the gel’s ability to select flow channels, inhibits emulsifier channeling, and achieves a remarkable EOR effect.

A Practical Model for Water Injection Evaluation and Optimization in Typical Offshore Reservoirs Considering Formation Heterogeneity Based on Experimental Study

A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.