The microscopic occurrence and mobility of oil in shale matrix pores are the key factors that restrict the efficient exploitation of terrestrial shale oil. This paper carried out quantitative characterizations on the amount, proportion, distribution and mobility of oil with different states in shale matrix pores, and theoretically established a series of models evaluating adsorbed, free and mobile amounts, and oil-adsorbed proportion (i.e., adsorption ratio equation). A method based on saturation-centrifugation-nuclear magnetic resonance tests was established to evaluate the microscopic occurrence and mobility of pore oil. The aforementioned models and methods have been applied to the Shahejie Formation shale oil reservoir in the Dongying Sag, Jiyang Depression, Bohai Bay Basin, and revealed the microscopic occurrence and mobility of n-dodecane in shale matrix pores at 20 ℃ and atmospheric pressure. It is concluded that: (1) the amounts of adsorbed and free oil in organic-rich shales are generally higher than those in organic-bearing shales, and the ratio of adsorbed oil to free oil is mainly between 1 and 2. The storage spaces of adsorbed and free oil in different types of shales are obviously diverse. (2) The average density of adsorbed oil of organic-rich shale (0.8331 g/cm³) is slightly higher than that of organic-bearing shale (0.8067 g/cm³). The average thickness of adsorbed oil of organic-rich shale (1.7475 nm) is about 3 times that of organic-rich shale (0.5734 nm). It shows that the organic-rich shale has a stronger oil-rock interaction. (3) The minimum pore diameter of storing free oil (d_min) is equal to the product of the average thickness of adsorbed oil and the pore shape factor. The dmin of organic-rich shale is of 3.5~10.5 nm, and pores of mainly storing free oil (mass ratio >70%) have a diameter of about 100 nm. The dmin of organic-bearing shale varies from 1.1~3.4 nm, and pores of mainly storing free oil have a diameter of about 30 nm. (4) The mobility index of oil in organic-rich shale (mean 6.24 mg·g^-1·MPa^-1) is higher than that in organic-bearing shale (mean 5.20 mg·g^-1·MPa^-1), and pore oil has a better mobility when the ratio of adsorbed oil to free oil is about 1.5. (5) Based on the oil-rock interaction, the coupling relationship of the oiliness and storage space of shale with the mobility of shale oil are established, and the internal relation between them is described mathematically, which will lay a theoretical foundation for discovering high-quality shale oil reservoirs.

Permeability is one of the most important petrophysical properties of shale reservoirs, controlling the fluid flow from the shale matrix to artificial fracture networks, the production and ultimate recovery of shale oil/gas. Various methods have been used to measure this parameter in shales, but no method effectively estimates the permeability of all well intervals due to the complex and heterogeneous pore throat structure of shale. A hydraulic flow unit (HFU) is a correlatable and mappable zone within a reservoir, which is used to subdivide a reservoir into distinct layers based on hydraulic flow properties. From these units, correlations between permeability and porosity can be established. In this study, HFUs were identified and combined with a back propagation neural network to predict the permeability of shale reservoirs in the Dongying Depression, Bohai Bay Basin, China. Well data from three locations were used and subdivided into modeling and validation datasets. The modeling dataset was applied to identify HFUs in the study reservoirs and to train the back propagation neural network models to predict values of porosity and flow zone indicator. Next, a permeability prediction method was established, and its generalization capability was evaluated using the validation dataset. The results identified five HFUs in the shale reservoirs within the Dongying Depression. The correlation between porosity and permeability in each HFU is generally greater than the correlation between the two same variables in the overall core data. The permeability estimation method established in this study effectively and accurately predicts the permeability of shale reservoirs in both cored and un-cored wells. Predicted permeability curves effectively reveal favorable shale oil/gas seepage layers and thus are useful for the exploration and the development of hydrocarbon resources in the Dongying Depression.

Due to abundant nanoscale pores developed in shale, gas flow in shale presents a complex dynamic process. This paper summarized the effects from effective stress increase, shale matrix shrinkage, gas slippage and Knudsen diffusion on the gas permeability change in shale during shale gas recovery. With the reduce in gas pressure, effective stress increase leads to the decline of the permeability in an exponential form; the permeability increases due to the shale matrix shrinkage induced by gas desorption; appearances of gas slippage and Knudsen diffusion cause an additional increase in the gas permeability particularly in small pores at low pressures. In addition, some reported models evaluating the shale permeability were reviewed preliminarily. Models considering these four effects may be potentially effective to evaluate the gas permeability change in shale.