Optimizing oil recovery from mature reservoirs remains a key challenge in the petroleum industry. This study evaluates the efficiency of CO₂-WAG injection compared to continuous CO₂ and water flooding using a sector model of the X Oil Field. A compositional reservoir simulator was employed to analyze oil recovery under water-wet and mixed-wet conditions, incorporating three-phase relative permeability and wettability effects. The results show that continuous CO₂ flooding yields the highest oil recovery, with water-wet systems outperforming mixed-wet reservoirs. CO₂-WAG injection provides a balanced approach, enhancing recovery while enabling CO₂ sequestration, but remains less effective than continuous CO₂ flooding. Water flooding, though the least efficient in terms of oil recovery, demonstrates long-term production stability. The gas–oil ratio (GOR) is notably higher in CO₂-WAG, indicating gas breakthrough challenges. These findings emphasize the significant role of wettability in enhanced oil recovery (EOR) and suggest that continuous CO₂ flooding is the most effective technique for maximizing production in heterogeneous reservoirs. This study contributes valuable insights for optimizing injection strategies, improving hydrocarbon recovery, and supporting sustainable reservoir management.

Multi-stage hydraulic fracturing is a key technology adopted in the energy industry to make shale gas and shale oil fields profitable. Post-frac fluid soaking before putting wells into production has been found essential for enhancing well productivity. Finding the optimum time to terminate the fluid-soaking process is an open problem to solve. Post-frac shut-in pressure data from six wells in two shale gas fields were investigated in this study based on pressure transient analysis (PTA) to reveal fluid-soaking performance. It was found that pressure-derivative data become scattering after 1 day of well shut in. The overall trend of pressure-derivative data after the first day of well shut in should reflect the effectiveness of fluid soaking. Two wells exhibited flat (zero-slope) pressure derivatives within one week of fluid soaking, indicating adequate time of fluid soaking. Four wells exhibited increasing pressure derivatives within one week of fluid soaking, indicating inadequate time of fluid soaking. This observation is consistent with the reported well’s Estimated Ultimate Recovery (EUR). This study presents a new approach to the assessment of post-frac fluid-soaking performance with real-time shut-in pressure data.

Significant amounts of oil often remain in reservoirs after traditional waterflooding. Water-Alternating-CO₂ (CO₂-WAG) injection has shown to be a more efficient technique for recovering residual oil, leveraging successive imbibition and drainage cycles. Effective simulation of WAG injection requires a thorough understanding of three-phase relative permeability. In this study, a sector model of the X Oil field reservoir was developed to assess the potential of WAG injection, compared to continuous water and CO₂ flooding. The model area was selected to represent the field's geological and material-balance regions, with a natural closed boundary around its exterior surfaces. Simulations were conducted using the GEM simulator for different wettability characteristics (water-wet and mixed-wet) to evaluate oil recovery across three injection methods: CO₂-WAG, continuous water, and continuous CO₂ injection.The results indicate that continuous CO₂ injection yields a higher oil recovery factor than other methods in both water-wet and mixed-wet systems. However, the water-wet system outperformed the mixed-wet system in terms of overall recovery efficiency, highlighting the significant impact of wettability on EOR performance. This study provides valuable insights into optimizing injection strategies for enhanced oil recovery (EOR).

Multi-stage hydraulic fracturing is a key technology adopted in the energy industry to make shale gas and shale oil fields profitable. Post-frac fluid soaking before putting wells into production has been found essential for enhancing well productivity. Finding the optimum time to terminate the fluid-soaking process is an open problem to solve. Post-frac shut-in pressure data from six wells in two shale gas fields were investigated in this study based on Pressure Transient Analysis (PTA) to reveal fluid-soaking performance. It was found that pressure derivative data become scattering after 1 day of well shut in. The overall trend of pressure derivative data after the first day of well shut-in should reflect the effectiveness of fluid-soaking. Two wells exhibited flat (zero-slope) pressure derivatives within one week of fluid-soaking, indicating adequate time of fluid-soaking. Four wells exhibited increasing pressure derivatives within one week of fluid-soaking, indicating inadequate time of fluid-soaking. This observation is consistent with reported well’s Estimated Ultimate Recovery (EUR). This study presents a new approach to assessment of post-frac fluid-soaking performance with real-time shut-in pressure data.