Experimental study on the injectivity, adsorption, and in-situ rheology of HPAM polymer in intact and fractured sandstone

Optimizing oil production from existing resources has become the primary strategy for many oil-producing companies globally. The increasing demand for extracting from unconventional resources has spurred the adoption of Enhanced Oil Recovery (EOR) techniques. Among these, polymer flooding stands out as an attractive option for many reservoirs. The goal of polymer flooding techniques is to regulate water mobility within the reservoir, thereby enhancing oil recovery. However, the presence of natural and artificially induced fractures in a reservoir significantly impacts fluid flow patterns and the efficiency of hydrocarbon recovery. Fractures can negatively affect the recovery process by creating bypass paths, particularly in production-injection systems. With the presence of many reservoirs, including fractured, amenable for polymer flooding, it is crucial to understand the effect of fractures on the movement of polymer in porous media. This study investigates the injectivity, retention, and in situ rheology of a typical HPAM polymer in both fractured and unfractured sandstones. The objective is to compare the effect of fractures on the behavior of polymer solution flow in sandstone reservoirs. To achieve this, two coreflooding experiments were conducted: one with an unfractured core and the other with a fractured core. During each experiment, the flow of polymer solutions with varying concentrations was tested under different injection rates. Specifically, three slugs of polymer at concentrations of 2000 ppm, 1000 ppm, and 500 ppm were injected, with water injections separating each slug. For each slug, four different injection flow rates were examined (1.5, 1.0, 0.75, and 0.1 cc/min). The results showed that the presence of a fracture significantly impacts the flow behavior of HPAM solutions in porous media. Lower pressure drops were observed in the fracture core compared to intact (unfractured) core, thereby raising the limiting injection rate for polymer. For example, for slug 1 (2000 ppm), the pressure drop for unfractured core at injection rate of 1.5 cc/min was 325 psi while for the fractured core it was 3.21 psi. Additionally, the presence of a fracture influences the shear thickening behavior of the polymer, with lower onset velocity values observed in the fracture core. Polymer flow behaved differently in the presence of a fracture compared to high permeability rock. Furthermore, lower retention values were observed in the presence of fracture. The experimental results showed that the polymer retained in the unfractured core after the first, the second and the third water wash out were 57.98, 63.25, 63.56 mg/100 gm of rock, respectively, compared to 4.78, 1.19, and 0.12 mg/100 gm in the fractured core. Despite the decrease in fracture conductivity, the results showed that the fracture remained opened during polymer flow.