Iranian Journal of Oil and Gas Science and Technology

Abstract Experimental analysis and numerical simulation of CO₂ injection in oil and gas reservoirs are essential for CO₂ sequestration and enhanced oil recovery applications. However, experimental approaches are often expensive and time-consuming, while numerical methods require input parameters such as two-phase relative permeabilities. In this study, two-phase flow simulations are conducted using a numerical solver based on the phase-field approach under steady-state conditions to determine relative permeability curves. Specifically, flow simulations are performed in realistic porous media, and nonconstant fluid viscosity and density are incorporated, addressing limitations of previous studies. Therefore, the main contribution of this work is the determination of CO₂–oil relative permeabilities in realistic porous media extracted from micro-CT images under conditions of variable fluid viscosity and density. In addition, the influences of wetting properties and hysteresis on relative permeability behavior are investigated.
The numerical results indicate that increased wettability toward the injected fluid enhances displacement efficiency by shifting the intersection point of the relative permeability curves to the right, leading to higher oil recovery, particularly at larger contact angles corresponding to non-wetting conditions and at lower surface tensions. Furthermore, the separation between imbibition and drainage relative permeability curves, representing hysteresis effects, becomes more pronounced as wettability shifts toward larger contact angles. These findings demonstrate the capability of steady-state pore-scale simulations based on the phase-field approach to reliably determine CO₂–oil relative permeability curves when realistic porous media and nonconstant fluid properties are considered.

Abstract Cocurrent spontaneous imbibition (COCSI) of an aqueous phase into matrix blocks arising from capillary forces is an important mechanism for petroleum recovery from fractured petroleum reservoirs. In this work, the modeling of countercurrent imbibition is used to develop the appropriate scaling equations. Considering the imbibition process and the water and oil movement respectively as the wet phase and the non-wet phase in a block saturated by oil and surrounded by two vertical fractures full of water, a differential equation having partial and nonlinear derivatives is introduced using Darcy and mass balance equations. On the other hand, as there is no analytical solution for this equation, a new equation is introduced by considering the different intervals of the wet and non-wet phase viscosity and by selecting the best suitable functions for relative permeability and capillary pressure. Considering the boundary conditions governing the countercurrent imbibition, an analytical solution (equation) is developed. Finally, the developed equation is validated. The results of this research can be very important for a better understanding of the imbibition process and the water and oil movement in the fractured environments.

Abstract Gravity drainage is the main mechanism which controls the oil recovery from fractured reservoirs in both gas-cap drive and gas injection processes. The liquid bridge formed between two adjacent matrix blocks is responsible for capillary continuity phenomenon. The accurate determination of gas-liquid interface profile of liquid bridge is crucial to predict fracture capillary pressure precisely. The liquid bridge interface profile in the absence and in the presence of gravity is numerically derived, and the obtained results are compared with the measured experimental data. It is shown that in the presence of gravity, fracture capillary pressure varies across the fracture, whereas, by ignoring gravitational effects, a constant capillary pressure is obtained for the whole fracture. Critical fracture aperture which is the maximum aperture that could retain a liquid bridge was computed for a range of liquid bridge volumes and contact angles. Then, non-linear regression was conducted on the obtained dataset to find an empirical relation for the prediction of critical fracture aperture as a function of liquid bridge volume and contact angle. The computation of fracture capillary pressure at different liquid bridge volumes, fracture apertures, and contact angles demonstrates that if the liquid bridge volume is sufficiently small (say less than 0.5 microliters), capillary pressure in a horizontal fracture may reach values more than 0.1 psi, which is comparable to capillary pressure in the matrix blocks. The obtained results reveal that the variation of fracture capillary pressure versus bridge volume (which represents liquid saturation in fracture) obeys a trend similar to the case of matrix capillary pressure. Therefore, the capillary pressure of matrix can be applied directly to fractures considering proper modifications. The results of this study emphasize the importance of capillary continuity created by liquid bridges in the performance of gas-oil gravity drainage in fractured reservoirs.

Abstract In this study, a chemical additive made by a combination of polymer, alkaline, and silica nano
particles is used to control the oil recovery and relative permeability curves. Various parameters
including the type and concentration of polymer, alkaline, and nanosilica particles have been studied.
To evaluate the efficiency of these additives, we performed unsteady state displacement experiments
under the JBN method and determined the pressure gradient across the core samples. The
experimental observations emphasized that by using the appropriate chemical additives the relative
permeability of the phases is changed towards higher oil relative permeability values, which results in
the oil recovery. The results of this study can improve the chemical flooding for heavy oil recovery.

Abstract The mathematical modeling of fracture networks is critical for the exploration and development of natural resources. Fractures can help the production of petroleum, water, and geothermal energy. They also greatly influence the drainage and production of methane gas from coal beds. Orientation and spatial distribution of fractures in rocks are important factors in controlling fluid flow. The objective function recently developed by Masihi et al. 2007 was used herein to generate fracture models that incorporate field observations. To extend this method, simulated annealing, genetic, and tabu search algorithms were employed in the modeling of fracture networks. The effectiveness of each algorithm was compared and the applicability of the methodology was assessed through a case study. It is concluded that the fracture model generated by simulated annealing is better compared to those generated by genetic and tabu search algorithms.