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This work is devoted to CO2 Huff-n-Puff studies on heavy oil. Oil recovery for heavy oil reservoirs is sufficiently small in comparison with conventional reservoirs, and, due to the physical limitation of oil flow through porous media, a strong need for better understanding of tertiary recovery mechanisms of heavy oil exists. Notwithstanding that the idea of Huff-n-Puff gas injection technology for enhanced oil recovery has existed for dozens of years, there is still no any precise methodology for evaluating the applicability and efficiency of this technology in heavy oil reservoirs. Oil recovery factor is a question of vital importance for heavy oil reservoirs. In this work, we repeated Huff-n-Puff tests more than three times at five distinct pressure points to evaluate the applicability and efficiency of CO2 Huff-n-Puff injection to the heavy oil reservoirs. Additionally, the most critical factor that affects oil recovery in gas injection operation is the condition of miscibility. Experimental data allowed to distinguish the mixing zone of the light fractions of studied heavy oil samples. The experimental results showed that the pressure increase in the Huff-n-Puff injection process does not affect the oil recovery when the injection pressure stays between miscibility pressure of light components of oil and minimum miscibility pressure. It was detected that permeability decreases after Huff-n-Puff CO2 tests.

Summary For the purpose of this work, the authors used an integrated approach to the modeling of in-situ combustion (ISC) including the results of laboratory studies and preliminary works, which significantly affect the choice of the method for implementing ISC and the results obtained in the process of modeling. The laboratory studies provided the data on the temperature range of the beginning of high-temperature oil oxidation, which is to be achieved during the modelling of the bottomhole zone heating. Based on the resulting injectivity profile, the reservoir distribution within the injection well zone in the geological model was updated. A high-permeability channel between the injection well and one of the production wells revealed during cold water injection explains the main oil production increment resulting from ISC and demonstrated by the reservoir simulation model. Based on the results of model runs for a more uniform distribution of the effect between producing wells, the best start-up time for the most reactive well was determined. Using dynamic modeling of in-situ combustion in a carbonate reservoir, the parameters of this technology implementation were found, and incremental oil production was estimated. For the first time, the ISC technology is planned for implementation in a carbonate reservoir with high-viscosity oil in Samara region. The developed integrated approach to the dynamic modeling of in-situ combustion, which considers both the laboratory studies and preparatory work data, enables the most accurately determination of the best ISC technological parameters and this technology contribution.

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