Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance

Abstract

Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100–1500 m require technology that can achieve sufficiently high fluid temperature (250–300 °C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling.The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called “aquathermolysis” to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons.A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.