CO 2 Huff-n-Puff (HnP) is an effective technique for enhancing oil recovery (EOR) that can be applied to shale oil reservoirs faced with poor natural productivity and low water injectivity. The main objective of this study is to investigate the interactions of CO 2 and formation crude oil, and evaluate the CO 2 HnP performance in shale oil reservoirs in the Qianjiang depression in China. In this study, the variation rules of oil phase behavior, viscosity, saturation pressure, and swelling factor at different CO 2 contents of 0 to 65% were studied. A series of HnP experiments were conducted. The factors affecting the oil recovery were discussed, and Nuclear Magnetic Resonance (NMR) tests were conducted on core samples at different stages of the HnP process. The results show that the injected CO 2 can make an positive change in the crude oil phase behavior. The oil-gas two-phase region enlarges and the saturation pressure increases as more CO 2 is dissolved in the formation oil, which is beneficial to oil production. The dissolution of CO 2 in the oil phase increased the oil swelling degree by 1.492 times, and the viscosity decreased from 1.944 to 0.453 mPa s. The HnP experimental results demonstrate that the soaking time should be determined based on the injection pressure. Miscible conditions is a viable option for CO 2 HnP as 10% more oil can be produced using miscible HnP and save more than half of the soaking time.The results illustrate that fracture is the most important factor affecting oil recovery, and the performance of HnP EOR on core samples with fractures is almost 25% better than those without fractures. However, the core matrix permeability has an almost negligible effect on the performance of CO 2 HnP. The NMR tests show that the oil recovered in the first cycle was dominated by macropores and mesopores, followed by small pores. In the latter HnP cycles, the oil in small pores and micropores becomes the main oil-producing area. This study may provide a better understanding of the CO 2 HnP enhanced recovery strategy for shale reservoirs.
The irreducible water saturation (S wir) is a significant parameter for relative permeability prediction and initial hydrocarbon reserves estimation. However, the complex pore structures of the tight rocks and multiple factors of the formation conditions make the parameter difficult to be accurately predicted by the conventional methods in tight gas reservoirs. In this study, a new model was derived to calculate S wir based on the capillary model and the fractal theory. The model incorporated different types of immobile water and considered the stress effect. The dead or stationary water (DSW) was considered in this model, which described the phenomena of water trapped in the dead-end pores due to detour flow and complex pore structures. The water film, stress effect and formation temperature were also considered in the proposed model. The results calculated by the proposed model are in a good agreement with the experimental data. This proves that for tight sandstone gas reservoirs the S wir calculated from the new model is more accurate. The irreducible water saturation calculated from the new model reveals that S wir is controlled by the critical capillary radius, DSW coefficient, effective stress and formation temperature.
Threshold pressure gradient has great importance in efficient tight gas field development as well as for research and laboratory experiments. This experimental study is carried out to investigate the threshold pressure gradient in detail. Experiments are carried out with and without back pressure so that the effect of pore pressure on threshold pressure gradient may be observed. The trend of increasing or decreasing the threshold pressure gradient is totally opposite in the cases of considering and not considering the pore pressure. The results demonstrate that the pore pressure of tight gas reservoirs has great influence on threshold pressure gradient. The effects of other parameters like permeability and water saturation, in the presence of pore pressure, on threshold pressure gradient are also examined which show that the threshold pressure gradient increases with either a decrease in permeability or an increase in water saturation. Two new correlations of threshold pressure gradient on the basis of pore pressure and permeability, and pore pressure and water saturation, are also introduced. Based on these equations, new models for tight gas production are proposed. The gas slip correction factor is also considered during derivation of this proposed tight gas production models. Inflow performance relationship curves based on these proposed models show that production rates and absolute open flow potential are always be overestimated while ignoring the threshold pressure gradients.
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