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Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the "injection + soaking" stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the "huff" stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved. [ABSTRACT FROM AUTHOR]

Viscosity reducer flooding has been successfully applied in tertiary oil recovery of ordinary heavy oil reservoirs. However, lowering interfacial tension or reducing oil viscosity, which is more critical for viscosity reducer to improve oil recovery of ordinary heavy oil, has not yet formed a unified understanding, which restricts the further large-scale application of viscosity reducer flooding for ordinary heavy oil reservoir. Moreover, when the dominant water flow channel is formed in the reservoir, the sweep efficiency decreases sharply and can affect oil recovery efficiency of viscosity reducer. Therefore, in this study, the concept of branched-preformed particle gel (B-PPG) coupling viscosity reducer flooding is proposed. The oil-water interfacial tension performance, emulsification ability, and viscosity reduction performance of three different viscosity reducers were evaluated. The enhanced oil recovery ability of viscosity reducers, B-PPG, and viscosity reducer/B-PPG composite systems was investigated by performing sand pack flooding experiments. The results show that the oil-water interfacial tensions of the three viscosity reducers S1, S2, and S3 are 0.432 mN·m-1, 0.0112 mN·m-1, and 0.0031 mN·m-1, respectively. S1 with the highest interfacial tension has the best emulsification and viscosity reduction performance, S2 is the second, and S3 is the worst. The lower the interfacial tension, the worse the emulsification stability. The sand pack flooding results show that the incremental oil recovery of viscosity reducer S2 flooding is the largest, 7.5%, followed by S1, 7.3%, and S3, 5.6%. The viscosity reducer S2 with moderate interfacial tension and emulsifying capacity has the best ability to improve the recovery of ordinary heavy oil. The incremental oil recovery of B-PPG is 12.7%, which is significantly higher than that of viscosity reducer flooding. Compared with viscosity reducing flooding, the viscosity reducer/B-PPG composite systems have better enhanced oil recovery capacity. The findings of this study can help for better understanding of enhancing oil recovery for ordinary heavy oil reservoir. [ABSTRACT FROM AUTHOR]

Considering the significant importance of emulsification for heavy oil recovery, a good‐emulsification‐oriented (GEO) (rather than the conventional ultralow interfacial tension (IFT) oriented) surfactant‐polymer (SP) system was employed to remove heavy oil. Specifically, the emulsification behavior and viscosity‐reduction property of heavy oil in porous media were first studied by flood tests. Then, such a GEO SP was used to displace heavy oil for recovery measurement. It is found that first, as migration increases in porous media, the in situ emulsified oil droplets evolve into smaller and more uniform droplets (without coalescence), thus, exhibit self‐adjustment ability to match with, and plug, the pores. An increase in surfactant content and seepage velocity also makes the emulsion's particles smaller and more uniformly distributed. Second, such oil‐in‐water emulsification indeed helps to reduce heavy oil viscosity in porous media and there is an optimal surfactant content for such viscosity reduction: The lower the water cut, the greater the optimal surfactant content, the worse the viscosity‐reduction effect. Third, on its own, the GEO surfactant performs very poorly in recovering heavy oil and is even worse than the single polymer; therefore, such a surfactant should be jointly used with a polymer in an SP system instead of on its own, but an excessive surfactant content in the SP seems to hinder the recovery, while the large slug size tends to contribute significantly to an improved oil recovery. [ABSTRACT FROM AUTHOR]

The heterogeneous phase combination flooding (HPCF) system which is composed of a branched-preformed particle gel (B-PPG), polymer, and surfactant has been proposed to enhance oil recovery after polymer flooding in heterogeneous reservoirs by mobility control and reducing oil–water interfacial tension. However, the high cost of chemicals can make this process economically challenging in an era of low oil prices. Thus, in an era of low oil prices, it is becoming even more essential to optimize the heterogeneous phase combination flooding design. In order to optimize the HPCF process, the injection strategy has been designed such that the incremental oil recovery can be maximized using the corresponding combination of the B-PPG, polymer, and surfactant, thereby ensuring a more economically-viable recovery process. Different HPCF injection strategies including simultaneous injection and alternation injection were investigated by conducting parallel sand pack flooding experiments and large-scale plate sand pack flooding experiments. Results show that based on the flow rate ratio, the pressure rising area and the incremental oil recovery, no matter whether the injection strategy is simultaneous injection or alternation injection of HPCF, the HPCF can significantly block high permeability zone, increase the sweep efficiency and oil displacement efficiency, and effectively improve oil recovery. Compared with the simultaneous injection mode, the alternation injection of HPCF can show better sweep efficiency and oil displacement efficiency. Moreover, when the slug of HPCF and polymer/surfactant with the equivalent economical cost is injected by alternation injection mode, as the alternating cycle increases, the incremental oil recovery increases. The remaining oil distribution at different flooding stages investigated by conducting large-scale plate sand pack flooding experiments shows that alternation injection of HPCF can recover more remaining oil in the low permeability zone than simultaneous injection. Hence, these findings could provide the guidance for developing the injection strategy of HPCF to further enhance oil recovery after polymer flooding in heterogeneous reservoirs in the era of low oil prices. [ABSTRACT FROM AUTHOR]