Abstract
Formation damage due to fines migration is a major reason for well productivity decline for oil and gas wells. Formation fines are small enough to pass through pore throats causing pore plugging and permeability decline. Different factors affect fines migration such as flow rate, salinity, pH value, reservoir temperature and oil polarity, as well as changes in chemical environment induced by Enhanced Oil Recovery (EOR) agents. This paper focuses on the effect of flow rates on fines detachment from the grain surfaces, which causing permeability reduction. As the fluid inside the reservoir moves towards the wellbore, the fluid velocity increases, when the fluid reaches the critical flow rate these fines can be picked up into the fluid. These fines captured by thinner pore throats causing pore plugging and permeability reduction. Different concentrations of nanoparticles were used to fix these fines on their sources and prevent their mobilization at high flow rates. The unique technique used in this study is changing the potential surfaces between fines and grain surfaces to prevent fines movement above the critical flow rate. SiO2 and MgO NPs used in this study can be adsorbed on the pore surfaces and reduce the repulsion forces between fines and pore surfaces. SiO2 and MgO nanoparticles at different concentrations (0.25, 0.50 and 0.75 g/L) were used on treating the Abu-Rawash sandstone reservoir using Formation Damage System Cell FDS-350. The experimental studies showed that using MgO NPs would prevent fines detachment from the pore surfaces and decrease the reduction of permeability at high flow rates more than SiO2 NPs. The optimum concentration of MgO NPs was at 0.5 g/L as the permeability remediation at this concentration reaches to 64.83%.
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