No abstract

Production enhancement by low-salinity waterflood in carbonate formations is a subject of intense speculation. Several mechanisms are attributed to enhanced oil recovery by low-salinity waterflooding in carbonate formations. Review of experimental data in the literature indicates that the main mechanism involves interaction of Na+, Cl−, Ca2+, Mg2+, SO42− and crude oil carboxylate ions (R-COO−) with the rock in the electrical double layer (EDL) near the surface of carbonate pores, leading to wettability alteration. In this study, we performed four seawater floods in heterogeneous low-permeability carbonate cores followed by low-salinity floods. The core permeability is between 0.5 to 1.5 md, and porosity in the range of 18 to 25%. Cores were aged for eight weeks at reservoir pressure and temperature. We also conducted pendant drop oil-brine IFT measurement, and captive oil-droplet contact angle at different brine salinity, with and without the presence of surfactant. The carbonate core flood results show that removing NaCl from seawater or diluting the seawater twice and four times yielded about 8% incremental oil. In one experiment, the change in the effluent ionic concentrations was measured, and it was observed a decrease in Ca2+, Mg2+, Cl−, and SO42−. Using pendant drop IFT measurements, oil-brine IFT increased with decreasing salinity both in presence and in absence of 1,000-ppm surfactant. From captive oil-droplet contact-angle measurements, it was observed that cleaned un-aged carbonate core slabs were water-wet, and became more water-wet as salinity decreased (both in presence and in absence of 1000-ppm surfactant). The wettability of crude-aged carbonate core slabs altered from oil-wet to intermediate-wet as salinity decreased. And, the wettability changed from intermediate-wet to water-wet with decreasing salinity in presence of 1,000-ppm surfactant. Moreover, addition of small amount of surfactant alters the wettability of crude-aged or cleaned un-aged carbonate core slabs towards water-wet. The degree of water-wetness achieved by surfactant solution depends on salinity level.

Polymer flooding is one of the most commonly employed improved oil-recovery techniques. However, its successful application is related to favorable reservoir conditions and geology. In addition, its application in high-temperature, high-salinity (HT-HS) carbonate reservoirs is still a challenging task. A series of laboratory core-flood experiments have been performed at reservoir conditions (temperature of 120 °C and salinity of 167 g/L) on carbonate outcrop core samples to evaluate the flow behavior of polymer injection. A baseline with continuous polymer injection is established initially, and the experimental data are then history-matched to generate the relative permeability curves for the process using commercial software. Various parameters including reservoir permeability, polymer-slug size, polymer initiation time, and flow rate are varied to determine the optimum flooding conditions. All of the simulation results are then revalidated with the experimental results. Encouraging results are obtained at the optimum conditions despite the mechanical degradation of the polymer, which shows up to 85% recovery of the original oil in place with manageable polymer adsorption on the rock surface. It is also observed that the potential polymer can work effectively on the core samples having moderate (30 mD) to high-permeability samples; however, the polymer loses its efficiency in lower-permeability rock samples. The results also indicate that early polymer injection helps to reduce the polymer-slug size required to reach residual oil saturation. The optimum conditions for polymer-slug size and polymer initiation time is 0.1 pore volume after 0.3 pore volume of water injection, respectively. The smaller polymer-slug size also helped to manage the resistance factor and the residual resistance values in the desirable range, i.e., 1.9 and 1.1, respectively. Identifying a polymer that can withstand high-temperature and high-salinity conditions in carbonate reservoirs will be a major step toward broadening the scope of successful polymer-flooding applications.