Shaobin Hu

Under the background of “double carbon” target, injection of CO2 into oil reservoirs has attracted a lot of attention as a key technology pathway to enhance crude oil recovery and realize geological storage of CO2. In the past decade, CCUS (Carbon Capture, Utilization and Storage) technology has become a research hotspot in the process of global energy transition by virtue of its dual benefits of carbon reduction and production increase in the oil and gas industry. Currently, most of the major oilfields in China have been under water-driven development for a long period of time, and they are facing the problem of high and stable production, and their development programs need to be adjusted urgently. Based on the above situation, this study carried out indoor oil drive physical simulation experiments, aiming to compare the effect of CO2 oil drive after water drive. The experimental results show that CO2-assisted oil drive is effective, the recovery rate from the test basis and technical reference, is expected to help the oilfield to meet the energy demand at the same time, and effectively promote the realization of the “double carbon” goal.

Mechanism analysis and technical scheme optimization on CO₂ displacement and CO₂ storage are based on the high-pressure physical properties of CO₂-added formation oil. Oil and natural gas samples from the BZ25-1 block in the Bohai oilfield were used to conduct high-pressure physical property experiments to explore the impacts of CO₂-CH₄ mixed gas on the properties of formation oil. After injecting different amounts of mixed gas, the saturated pressure was measured by constant mass expansion test, the viscosity was measured by falling ball method, the expansion coefficient was measured by gas injection expansion test, and the gas–oil ratio and volume coefficient were obtained by single degassing test. The results show that with gas injection, the saturation pressure and dissolved gas–oil ratio of formation oil increase, the volume coefficient and expansion factor go up, while the oil viscosity reduces. With the increase in gas addition, the properties of formation oil continue to improve, but the increase in improvement becomes flat. With the increase in pressure, the amount of dissolved gas in the formation oil will also increase. High-purity CO₂ is more helpful to change the properties of formation oil, while the gas mixed with CH₄ is more beneficial to elevate the formation energy. For the BZ 25-1 block, the gas injection amount of about 80 mol% is appropriate and the CO₂ purity of 60% can well balance the oil properties improvement and the formation pressure elevation.

During the process of steam thermal recovery of heavy oil, steam channeling seriously affects the production and ultimate recovery. In this study, fly ash was used as the plugging agent, and then a series of plugging experiments based on the results of two-dimensional (2D) experiments were conducted to study the effect of plugging the steam breakthrough channels. The experimental results show that the inorganic particle plugging agent made from the fly ash had a good suspension stability, consolidation strength, and injection performance. Because of these characteristics, it was migrated farther in the formation with a high permeability than in the formation with a low permeability, and the plugging rate was greater than 99%. After steam injection, it had a good anti-flush ability and stable plugging performance in the formation. In terms of the oil displacement effect, oil recovery in the formation with a low permeability was effectively improved because of plugging. The results show that the inorganic particle plugging agent could effectively control the steam channeling and it improved the development effect of the heavy oil reservoir.

Multi-component thermal fluids stimulation is a feasible way to recover offshore heavy oil reservoir. As a new technology, its mechanism of enhanced oil recovery should be understood through systematic simulation experiments and quantitative analysis. Laboratory experiments were carried out to investigate the effects of temperature, natural gas, and various gases (N₂, CO₂, or N₂+CO₂) on the viscosity of heavy oil from Nanbao block of Bohai offshore oilfield. The results show that in the range of 56°C (reservoir temperature) to 120°C, natural gas saturated and degassed oils are all very sensitive to temperature, and the viscosity is reduced by more than 90% when heated to 120°C; under lower temperature condition, injection of 5MPa N₂, N₂+CO₂, or CO₂ can significantly reduce the viscosity of natural gas saturated heavy oil, with a viscosity reduction ratio of about 20%, 50%, and 80%, respectively, at 56°C. Therefore, heavy oil production by viscosity reduction can be achieved by raising temperature or through gas injection. Taking into account the equipment, heat loss, and cost of steam injection, the technology of moderate heating, auxiliary gas injection is very promising for the recovery of Nanbao heavy oil.