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To understand the effect of the spontaneous imbibition (SI) and waterflooding on oil recovery in the tight sandstone reservoirs, we selected three pairs of tight sandstone samples from the Ordos Basin in China to conduct the SI-plus-waterflooding and waterflooding-only experiments, and monitor the oil distribution and flow characteristics by using the low-field nuclear magnetic resonance (NMR) technology. One interesting observation was that oil extracted in the SI process mainly comes from macropores and micropores, which doesn't agree with the previous results wherein oil was produced from micropores, and oil was produced from the mesopores during the waterflooding after the SI process. The oil recovery factor of tight sandstone samples in the process of the SI-plus-waterflooding was more than 50%, and even more than 85%, which was greater than that in the waterflooding-only process. Moreover, we found that our tight sandstone samples behaved lower residual oil saturation, and wider oil-water two-phase co-flow region during the SI-plus-waterflooding process than that did during the waterflooding-only process. These differences in behavior appear to be linked to the fluid dynamic characteristics and capillary pressure acting on the flow fluid during the two processes. In summary, the SI-plus-waterflooding overcame the limitations related to waterflooding-only and further improved oil recovery factor in the tight sandstones. [ABSTRACT FROM AUTHOR]

Hydrate formation in foam drainage gas recovery wells and the shut in accidents caused by plugging have become an important problem that restricts the safe production of natural gas. The blockage and accumulation of hydrates is a gradual problem. This research goes beyond predicting the formation of hydrates and delves deeper into examining the rate of hydrate formation and the degree of pipeline blockage at different wellbore locations. First, the temperature model, pressure model, multiphase flow model, and hydrate plugging model of hydrate formation process are established from the equations of mass conservation, energy conservation, and momentum conservation. Second, an iterative approach is employed to solve the model, with a maximum error of 6.86% in model validation. Finally, sensitivity analysis shows that wellhead temperature, wellhead pressure, and foam viscosity have different effects on hydrate formation, maximum plugging position, and plugging degree. At the same time, combined with the actual drainage and gas production process, and the characteristics of hydrate blockage, proposed hydrate prevention measures can be taken to achieve safe production of natural gas. The research results indicate that a decrease in temperature signifies an increase in undercooling, resulting in an accelerated rate of hydrate formation and an elevated risk of hydrate blockage. The decrease in wellhead pressure leads to a decrease in the rate of hydrate formation and an increase in production, which is beneficial for the hydrate prevention. However, larger pressure differences and gas production rates will put higher requirements on equipment such as well control devices. An increase in foam viscosity will lead to increased pressure, foam compression, reduced drainage capacity, and intensified hydrate generation. Therefore, foam viscosity should be kept as small as possible to keep the foam stable. [ABSTRACT FROM AUTHOR]

Cluster spacing optimization in non-uniform stress field, with the optimal stimulated reservoir volume (SRV) as target, which is critical for deep shale gas fracturing performance. A non-uniform stress field characterization model and a fracture network propagation model were constructed. The diagrams of the optimal cluster spacing were drawn based on the fault development in the Y1-01 well area. The results showed that the horizontal well should be deployed at a distance of between 2,000 and 4,000 m from the first-level fault, 1,500 and 2,500 m from the second-level fault, 700 and 1,200 m from the third-level fault, and an acceptable distance from the fourth-level fault. The shorter the distance to the fault for first-level faults, the bigger difference in horizontal stress, which was not conducive for fracture network propagation, and the smaller the optimal cluster spacing. For second-level, third-level, and fourth-level faults, when the fault strike was less than 50°, the closer to the fault, the bigger the difference in horizontal stress and the smaller the optimal cluster spacing. When the fault strike was greater than 50°, the farther away from the fault, the bigger the difference in horizontal stress, and the smaller the optimal cluster spacing. [ABSTRACT FROM AUTHOR]