Enhanced oil recovery from oil-wet tight carbonates using engineered water




Shi, Yue (Ph. D. in petroleum engineering)

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Carbonate reservoirs hold more than half of the world’s oil. Around 60%-80% of the original oil in place (OOIP) is left behind in carbonate reservoirs after primary recovery and water flooding. Wettability and heterogeneity (i.e., existence of vugs and natural fractures) are two main factors that result in low oil recovery. The injected fluid is likely to flow through the fractures and bypass the oil in the matrix due to the high permeability of fractures and the negative capillary pressure (Pc) of the oil-wet matrix. The goal of this research is to develop cost-effective engineered water formulations (modifying ionic composition and/or adding surfactants, nanoparticles and acids) to enhance oil recovery from a target oil-wet tight carbonate reservoir and understand the key mechanisms. The effect of low salinity brine and surfactants was first evaluated. The low-salinity brine composition was optimized using zeta potential measurements, contact angle experiments, and a novel wettability alteration measure. Significant wettability alteration was observed on dolomite rocks at a salinity of 2,500 ppm. Thirty-seven surfactants were evaluated by performing contact angle, IFT and spontaneous imbibition experiments. Three (quaternary ammonium) cationic and one (sulfonate) anionic surfactants showed significant wettability alteration and produced 43% - 63% OOIP by spontaneous imbibition. At a low temperature (35°C), oil recovery by low salinity effect is small compared to that by wettability altering surfactants. To evaluate the selected low-salinity surfactant formulation, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores. The homogenous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary-surfactant flooding with secondary-surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Results suggest that the retention increases as initial oil saturation decreases. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions and can significantly improve oil recovery if the oil-wet reservoir is not well-swept. The role of nanoparticles in wettability alteration (oil-wet to water-wet) and wettability retainment (prevent water-wet surface from becoming oil-wet during a long-term exposure to oil) was also studied. A surface modified silica nanoparticle (SiNP) and an anionic sulfonate surfactant were tested. ζ-potential measurements showed that SiNP can firmly adsorb onto the carbonate surface and make the surface negatively charged, which keeps the organic acid oil molecules away from the surface. Wettability analysis and imbibition results showed that SiNP cannot change the wettability, but SiNP treated calcite surface can remain water-wet after aging in oil. In contrast, the anionic surfactant can alter wettability, but failed to retain wettability. The transport and retention of the SiNP in the porous rock were also evaluated. Wettability alteration is a slow process. Acids were evaluated as potential additives in surfactant water to facilitate wettability alteration and expedite oil production. Measurements were performed at both low temperature (35°C) and high temperature (80°C) to identify effective acids. Coreflood tests were performed to compare the EOR performance of selected acid-surfactant water with that of surfactant water. Micro-CT was also performed to investigate the possible pore structure change after acid treatments. The results showed that acetic acid and methyl acetate are good candidates for low temperature and high temperature applications, respectively. Besides wettability alteration (WA) surfactants, the surfactants which can develop ultra-low IFT were also identified through laboratory measurements. The performance of these two types of surfactants was systematically evaluated at the core scale and scaled-up to the reservoir scale. A reservoir-scale model was developed to simulate injection-soak-production (ISP) tests and evaluate performance of the selected surfactants at the field scale. Results showed that low-IFT surfactants have better injectivity during injection phase and results in higher oil recovery during production phase, and WA surfactants showed faster oil production during shut-in phase.


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