Ningtao Zhang,Shuxia Li,Litao Chen,Yang Guo,Lu Liu
The characteristics of gas-liquid two-phase flow in hydrate-bearing sediments (HBS) are critical for natural gas hydrate production . This study experimentally investigates the flow patterns in the presence of hydrates and employs the phase field method for accurate simulations. Additionally, flow pressure differences in a capillary model were analyzed, and the impacts of occurrence patterns, saturation, and wettability of hydrates were investigated by numerical simulation. The results show that flow patterns are predominantly influenced by flow velocity. At high flow rates (Reynolds number >10), different gas-liquid ratios result in a variety of flow patterns, including annular, Taylor, and bubble flow. However, at lower flow rates (Reynolds number <10), the flow pattern consistently manifests as Taylor flow, regardless of gas-liquid ratio variations. Notably, the Jamin effect (a significant pressure differential caused by hydrates within the flow) was observed, which intensifies with increasing hydrate saturation and decreasing contact angle. Pore-filling hydrate patterns, in contrast to grain-coating, exhibit a greater number of gas-liquid interfaces, leading to larger pressure differences and a more evident Jamin effect. These findings aid in understanding the fluid migration in HBS and help estimate the natural gas production capacity.
Hongtao Fu,Kaoping Song,Erlong Yang,Lihao Liang,Yu Zhao,Zhehui Jin
Shale oil is an unconventional energy resource, and its efficient development is a key focus of current energy research. China’s continental shale resources are abundant, with high clay content and poor physical properties. The development of shale oil reservoirs after horizontal well fracturing remains suboptimal, requiring further recovery enhancement. Surfactant imbibition oil recovery technology is recognized as one of the effective methods for enhancing oil recovery in unconventional reservoirs. This study proposes a novel experimental apparatus and method for dynamic imbibition, and also develops a three-dimensional (3D) micro pore-fracture dynamic imbibition model. Furthermore, surfactant selection criteria based on wettability and interfacial tension are established. The results show that Cetyltrimethylammonium bromide (CTAB) forms ion pairs on the surface of shale pores, rapidly removing the oil film covering the shale surface. This induces a wettability reversal, reducing the water-phase contact angle from 132° to 55.1°. The use of the CTAB surfactant solution resulted in an 11.5 percentage points improvement in final imbibition efficiency. After CTAB surfactant solution detaches oil droplets from the shale surface, more of the water phase comes into contact with the clay minerals and micro-damage structures in the shale. Hydration induces new micro-damage in the shale, which accumulate and evolve into micro-fractures, creating flow channels for shale oil transport. Another key mechanism for enhancing the dynamic imbibition efficiency of continental shale oil is to modify the shale surface wettability while strategically adjusting interfacial tension. The selection criteria for surfactants used in shale oil dynamic imbibition should require not only wettability alteration capability but also an appropriate interfacial tension ranging from 2 to 10 mN/m. This balances the promoting effect of capillary forces with the suppressing effect of the Jamin effect, thereby facilitating the movement of oil droplets within deformed pores. Significant variations in average pressure within the pores enhance micro dynamic imbibition efficiency in shale. In the practical development of shale oil reservoirs, providing effective short-cycle energy replenishment and altering the average pressure within shale pores are crucial for guiding the enhancement of recovery in continental shale oil reservoirs.
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