Critical Role of Pore-Scale Heterogeneities in Assessing Efficiency of Formation Damage Removal in Sandstone Reservoirs
نویسندگان
1 Empress Catherine II Saint Petersburg Mining University, Saint Petersburg, Russian Federation
2 Petro Behin Negareh Makhzan (PBNM) Co., Shiraz, Iran
3 Petro Behin Negareh Makhzan (PBNM) Co., Shiraz, Iran
4 Department of Petroleum Engineering, School of Chemical and petroleum Engineering, Shiraz University, Shiraz, Iran
5 Empress Catherine II Saint Petersburg Mining University, Saint Petersburg, Russian Federation
6 Department of Petroleum Engineering, School of Chemical and petroleum Engineering, Shiraz University, Shiraz, Iran
7 Department of Petroleum Engineering, School of Chemical and petroleum Engineering, Shiraz University, Shiraz, Iran
8 Department of Petroleum Engineering, School of Chemical and petroleum Engineering, Shiraz University, Shiraz, Iran
9 Empress Catherine II Saint Petersburg Mining University, Saint Petersburg, Russian Federation
doi
10.5829/ije.2025.38.07a.17چکیده
Formation damage is typically regarded as a detrimental phenomenon that necessitates effective treatment to optimize production efficiency and extend wellbore lifetime. This study introduces new standards to guide laboratory-based investigations into the efficiency of chemical solvents for mitigating formation damage in sandstone reservoirs, emphasizing pore-scale property changes and permeability recovery. Three sandstone core samples from an anonymous reservoir, characterized by varying geological and petrophysical properties, were subjected to initial damage through the injection of oil-based drilling fluids. Each sample was subsequently treated with a distinct chemical solvent to evaluate their respective efficiencies in restoring porosity and permeability. Advanced tomographic imaging and pore-scale analyses were employed to quantify changes before and after treatment, focusing on representative elementary volumes (REVs) along the samples. The findings highlight the critical influence of initial sedimentary heterogeneities on solvent efficiency. Variations in CT number, porosity, permeability, and tortuosity demonstrated spatial heterogeneity in solvent effectiveness along the injection pathway. Notably, tortuosity decreased across most REVs, particularly near the outlet, post-treatment, indicating improved fluid flow pathways. However, uniform and consistent improvements in porosity, pore size distribution, and permeability were not observed, underscoring the role of intrinsic geological variability. This study concludes that solvent efficiency is strongly influenced by the severity of initial sedimentary heterogeneities induced by formation damage, rather than being solely dependent on solvent type. To achieve reliable comparisons, future solvent performance evaluations must account for comparable levels of geological heterogeneity pre- and post-treatment. These findings provide actionable insights for optimizing solvent selection and developing more effective strategies for reservoir stimulation and formation damage remediation.
