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The objective of this study is to construct a refined microscopic transport model that elucidates the transport mechanisms of gas flow within micro-nano pores and fractures. The collective impact of various microscopic transport mechanisms was explained through the apparent permeability model, specifically related to gases such as methane and carbon dioxide, within the shale matrix. The apparent permeability models, taking into account microscopic transport mechanisms such as slippage flow, Knudsen diffusion, transition flow, and surface diffusion, were established individually. Subsequently, the influencing factors on apparent permeability were analyzed. The results demonstrate that the apparent permeability of the shale reservoir matrix is significantly influenced by pore pressure, temperature, pore size, and total organic carbon (TOC). As pressure decreases, the apparent permeability of Knudsen diffusion and surface diffusion increases, while the apparent permeability of slippage flow decreases. In addition, the apparent permeability of the reservoir matrix initially decreases and then increases. With increasing temperature, the apparent permeability of slippage flow, Knudsen diffusion, and surface diffusion all increase, as does the apparent permeability of the reservoir matrix. As pore size increases, the apparent permeability of surface diffusion and Knudsen diffusion decreases, while the apparent permeability of slippage flow and the reservoir matrix increases. Furthermore, an increase in TOC leads to no change in the apparent permeability of slippage flow and Knudsen diffusion, but an increase in the apparent permeability of surface diffusion and the reservoir matrix. The model presented in this paper enhances the multi-scale characterization of gas microflow mechanisms in shale and establishes the macroscopic application of these micro-mechanisms. Moreover, this study provides a theoretical foundation for the implementation of carbon capture, utilization, and storage (CCUS) in shale gas production. [ABSTRACT FROM AUTHOR]

Shunbei Oilfield is characterized by substantial heterogeneity and a complex oil–water relationship. The water-oil interface is dynamically changing, and it is a crucial parameter for reserve calculation and evaluation. The main purpose is to analyze the effect of fluid flow in multi-scale media on the water-oil interface. It is well known that the fracture-cavity reservoirs have well-developed fractures and karst caves, and their distribution is complex in Shunbei Oilfield. This paper presents a way to simplify the fracture-cavity system first, then uses a unit of oil wells as a system to study the water-oil interface, which avoids impact on the water-oil interface due to oil production. A detailed step by step procedure for solving the semi-analytical solution of water-oil interface in a fracture-cavity reservoir by using an explicit algorithm and a successive steady-state method is presented. The solution can be used to investigate water-oil interface behavior. In this paper, we validated this method with the actual data for a relatively similar actual reservoir. Sensitivity analyses about the effects of the main parameters including production rates, cave volume and initial oil–water volume ratio on interfacial migration velocity are also presented in detail. The water breaking time of oil wells is fully investigated. The water-oil interface movement chart under different development conditions is established to predict the water-oil interface in the late stage of oil well production and extend the waterless developing period. Being based on this chart, a water breakthrough warning can be realized, and oil recovery can be improved. The findings of the research have led to the conclusion that the rising speed of water-oil interface is proportional to the production rate, on the contrary, it is inversely proportional to cave volume and initial oil–water volume ratio. As well production goes on, the water-oil interface rises at different rates. After the well is put into production for one year, the water-oil interface rises by 16.38%, 12.56% and 4.24% according to the condition that production rate is 10%, the initial oil–water volume ratio is 0.7, and the cave volume is 100 × 104 m3. This method is not only suitable for any period and any well type in the development of Shunbei Oilfield; it also has the function of calculating the real-time water-oil interface of a single well and multi-wells. This new method has the characteristics of easy calculation and high accuracy. The method in this paper can be further developed as it has great applicability in fracture-cavity reservoirs. [ABSTRACT FROM AUTHOR]

During hydraulic fracturing, there is a temperature difference between the injected water and formation rock for shale gas wells. The objective of this study is to investigate how this temperature difference changes with time, and how it affects multiphase-flow modeling during the shut-in and flowback periods. We conducted numerical simulations to investigate the behaviors of fracture temperature in shale gas wells. The results show a significant increase in fracture temperature during the shut-in and flowback periods. Sensitivity analysis suggests that this temperature increase is strongly related to the thermal conductivity of formation rock, matrix permeability, and initial reservoir temperature. Simulation scenarios were further compared to investigate the effect of temperature on flowback data analysis. Without considering the thermal effect, flowback data analysis may yield an earlier fracture cleanup and overestimated fracture volume. In addition, this study suggests that the thermal effect may also have implications for optimizing flowback operations. [ABSTRACT FROM AUTHOR]