Many physical factors are affecting relative permeability. These factors could be wettability, interfacial tension, and pore size distribution of the porous media. All these factors significantly change the shape of the relative permeability curve. The change of interfacial tension of flowing phases can considerably change flow characteristics especially in gas condensate reservoir or gas injection into wells with near miscible conditions. Assuming that physical core properties and experiment conditions are constant, interfacial tension as the only variable would change relative permeabilities. Here our objective is to estimate relative permeability at lower interfacial tensions from immiscible relative permeability. We will also estimate the change of residual oil saturation with interfacial tensions. In this paper, we have implemented Michaelis Menten Kinetics model to evaluate residual oil as a function of interfacial tension. Also, a new set of correlations was purposed to calculate gas and oil relative permeability at different IFT. The accuracy of the model is then assessed against experimental data available in literature and predictions of a default model in commercial simulators (Coat's model). Although the model needs fewer input data and it requires fewer calculations than Coat's model, it improved predictions.

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Simulation of Water-Alternating-Gas (WAG) Experiments require precise estimation of hysteresis phenomenon in three-phase relative permeability. Most of the research available in the literature are focused on experiments performed on sandstone rocks and the study of carbonate rocks has attracted less attention. In this paper, a recently published hysteresis model by Heriot-Watt University (HWU) was used for simulation of WAG experiments conducted on mixed-wet homogenous carbonate rock. In this study, we simulated immiscible WAG experiments, which were performed under reservoir conditions on mixed-wet carbonate reservoir rock extracted from Abu Dhabi field by using real reservoir fluids. Experiments are performed with different injection scenarios and at high IFT conditions. Then, the results of the coreflood experiments were history matched using 3RPSim to generate two-phase and three-phase relative permeability data. Finally, the hysteresis model suggested by Heriot-Watt University was used for the estimation of hysteresis in relative permeability data. The performance of the model was compared with the experimental data from sandstones to evaluate the impact of heterogeneity on hysteresis phenomenon. It was shown that the available correlations for estimation of three-phase oil relative permeability fail to simulate the oil production during WAG experiments, while the modified Stone model suggested by HWU provided a better prediction. Overall, HWU hysteresis model improved the match for trapped gas saturation and pressure drop. The results show that the hysteresis effect is less dominant in the carbonate rock compared to the sandstone rock. The tracer test results show that the carbonate rock is more homogenous compared to sandstone rock. Therefore, the conclusion is that the hysteresis effect is negligible in homogenous systems.

The average recovery factor of current producing oil reservoirs is about 35-50% worldwide. Enhanced Oil Recovery (EOR) methods such as Water Alternating Gas (WAG) target the oil left in place and improve the final recovery of the developed fields. In a WAG injection plan, some reservoir blocks experience simultaneous gas and water flow. Therefore, Simultaneous Water And Gas (SWAG) injection experiments are performed to understand and simulate the fluid flow behaviour in these blocks more accurately. The experimental data we analyzed in this manuscript were obtained by performing a SWAG experiment using real reservoir rock and fluid (mixed-wet carbonate rock extracted from the Abu-Dhabi field). In miscible and immiscible experiments, the injected gas was Methane and CO2, respectively. We tried to simulate the experiments using Stone's, Baker's, and Stone's exponent models to evaluate the performance of these models in simulating SWAG experiments. It was shown that SWAG displacement can be simulated using Stone's first model and changing two-phase kr data as a matching parameter. The results showed that we do not need to correct the three-phase relative permeability in the low oil saturation region for simulating SWAG experiments. The study presented in this paper is novel in two aspects: first, the SWAG experiments were conducted in reservoir carbonate samples using real reservoir fluids; and second, even though many researchers have simulated the WAG experiments, not many have discussed the simulation of SWAG experiments. The results presented in this paper is of utmost importance for decision making, designing, and simulating CO2-EOR plans in giant Abu-Dhabi carbonate reservoirs.

Three phase relative permeability models are used widely by reservoir engineers to investigate the performance of petroleum reservoirs, in particular, for designing gas injection strategy or WAG injection projects. However, there are concerns about the validity of the existing models and the reliability of predictions made by these models. In this paper, we have assessed the performance of some of these models for WAG injection in carbonate rocks by comparing the prediction of the models with the results of coreflood experiments performed under reservoir temperature and pressure. Two phase relative permeability results were obtain from history matching the experimental data by using our in-house history matching software. The estimated gas/oil and water/oil relative permeability curves were then used to simulate the results of immiscible gas and water injection under different injection strategies using different three-phase kr models. The results of these simulations were compared with experimental results.