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Water injection into carbonate subsurface formations is commonly used for aquifer recharge, aquifer storage and recharge, and disposal of water produced from petroleum and CO2 sequestration fields. Fines migration induced permeability decrease impacts fluids flow and oil recovery during water injection into carbonate rocks. Previous studies did not consider fines migration in carbonate reservoirs as a mechanism. This thesis investigates fines migration mechanisms in carbonate rocks and its impact on oil recovery and injectivity. First, single-phase experiments are performed on Edwards Brown rock samples with the objective to investigate the mechanism of fines migration in dolomite rocks. In particular, the effect of temperature and types of ions have been investigated. Filtered-deaired distilled water and pure salts are used to prepare the injection fluids. Rock samples are injected with 0.63 mol/L brine followed by four sequential injections of diluted brine: 0.21 mol/L, 0.1 mol/L, 0.05 mol/L, and 0 mol/L (distilled water). Pressure difference is recorded across the rock sample throughout each experimental run and used to calculate permeability. Effluent is collected to characterize produced fines and elements. pH and particle concentration measurements are collected frequently. Scanning electron microscope images of inlet and outlet faces pre- and post-injection were taken to observe any changes. For the experimental runs performed at 25˚C, ultimate permeability decrease was 99.92% for seawater experimental run, 99.96% for NaCl brine experimental run, and nearly zero for CaCl2 brine experimental run. For CaCl2 brine experimental run, the only observed mineral reaction is mineral dissolution. For NaCl brine and seawater experimental runs, both mineral dissolution and cation exchange are observed, of which the latter appears to be the main mechanism for fines migration. Due to mineral dissolution, permeability increase is observed during 0.21 mol/L and 0.1 mol/L injection at high temperature. However, during distilled water injection, permeability decrease is found to be similar at both low and high temperatures. Secondly, an analytical model is developed to correct oil and water relative permeabilities by incorporating the difference between the measured and the injected phase pressures. The model is used to estimate maximum water and oil relative permeabilities in the following two-phase fines migration experiments. A modification of the Johnson–Bossler–Naumann (JBN) method is proposed to incorporate capillary pressure at the inlet and outlet of a rock sample. The experimental runs are performed on Berea and Obernkriechner sandstone rock samples. Sandstone samples are utilized to eliminate heterogeneity and mineral dissolution impact on relative permeability. Fluid is injected into Berea rock at capillary to viscous ratios 0.05, 0.1, 0.5, and 1 and into Obernkriechner rock at capillary to viscous ratios 0.05 and 0.25. Rock samples are initially saturated with 20 g/l NaCl water. The experimental observations are analysed using classical JBN and new modified JBN. The latter's relative permeability curves are found to closely match those derived by applying history matching to a numerical model. This indicates that modified JBN can be used to provide an initial guess for history matching. results also show that accurate estimates of threshold capillary pressure are crucial to obtaining accurate oil relative permeability estimates. In contrast to those derived from the JBN method, modified JBN relative permeabilities are independent of capillary to viscous ratio or injection rate. Two-phase fines migration experiments are performed on four Edwards Brown rock samples using seawater or CaCl2 brine as the aqueous phase, and Soltrol® 130 or crude oil as the oleic phase. Rock samples are initially fully saturated with 0.63 mol/L of the selected aqueous solution. This is followed by injecting the selected oil at a constant rate for at least 20 pore volumes to displace brine. Next, at least 5 pore volumes of 0.63 mol/L of the selected brine are injected to displace oil, and finally distilled water. Distilled water is used to stimulate fines migration because the single-phase experimental runs show the highest concentration of produced fines during distilled water injection. For CaCl2 brine, distilled water injection is found to recover no additional oil of either type of oil. However, for seawater, the fines production observed during distilled water injection is found to reduce water relative permeability by two orders of magnitude when Soltrol® 130 is used and by three orders of magnitude when crude oil is used. The seawater experimental runs also brought about additional oil recovery during distilled water injection: 18% when Soltrol® 130 is used and 3.4% when crude oil is used. This last result can be attributed to the plugging of pores due to fines migration, which can divert further injected water into previously unswept pores. |
