Modelling the Impact of Reservoir CO₂ on Polymer Flood Performance in Aishwariya Field

Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO₂ content; ~80-90 mole% CO₂ in the gas phase and ~10-40 mole% CO₂ in the oil phase. Formation water sample has shown CO₂ concentration of ~7500 ppm with a pH of ~5.6. The oil is moderately viscous and aqueous based chemical EOR techniques like polymer/ASP flooding have been identified as the most suitable for Aishwariya's field conditions. The presence of CO₂ decreases the pH of a system. The viscosity of polyacrylamide polymers is known to decrease with reduction in pH; however, to the best of author's knowledge, commercial simulators do not have any method to directly model this viscosity dependence on pH. Therefore, a procedure was developed to capture the impact of CO₂ on polymer in-situ viscosity in a reservoir simulation model.

An EOS based PVT model was first developed using PVT data from the field. This EOS was then used in a commercial compositional simulator to calculate the phase distribution of CO₂ during an injection process. The liquid-liquid partitioning coefficient for CO₂ was calculated as the ratio of CO₂ mole fraction in oil phase to that in water phase. A similar model was then created in an "advanced process" reservoir simulator which modelled component distributions based on partitioning coefficients. For simplicity, the solution gas was assumed to be entirely composed of CO₂. The CO₂ component was defined as part of the aqueous phase instead of the default oleic phase. Data which related polymer viscosity to pH were used to create a "Viscosity-pH" table; other data permitted the construction of a "pH-CO₂ concentration" relationship. Linking these two tables together allowed the development of a "Viscosity-CO₂" function. Defining the CO₂as an "aqueous phase salt component" enabled us to model the polymer viscosity variation with CO₂ concentration. Simulation runs were then carried out both with and without the effect of CO₂ on polymer viscosity and the results were compared.

The developed approach captured the impact of CO₂ on the simulated polymer flood performance. It permitted us to quantify the amount of additional polymer that would be required to compensate for polymer viscosity loss in the presence of CO₂. It helped to improve our confidence in polymer flood performance predictions for this field despite the presence of a significant amount of CO₂.

The paper presents a step by step approach of utilizing commercially available simulation softwares to model the impact of in-situ CO₂ on polymer flood performance. The proposed method can be applied in fields with high concentrations of CO₂. The method can be extended for fields with lesser concentrations of CO₂.