No abstract

The movability of micro-remaining oil in microscale pores in tight reservoirs directly affects the recoverability of a reservoir fluid. Currently, core displacement and digital cores have been applied for the reservoir fluid movability and microstructure visualization. In this study, we present a practical framework for the pore-scale movability of tight oil, which combines core displacement tests and digital cores on real tight core samples. In this framework, the core displacement tests and miniature core displacement tests using three different displacement methods (water flooding, CH 4 flooding, and CO 2 flooding) are first performed. Then, through a series of CT (computed tomography) scanning results on the core displacement tests, a digital core model is constructed, and a distribution of micro-remaining oil is experimentally investigated. By combining the results of the miniature core displacement tests and the digital core model, the types and movability of tight oil at different times for the three methods are obtained. These results indicate that the remaining tight oil at pore scale can be classified into three different categories according to a shape factor (S) of the remaining oil, including block-like oil (4.85 > S > 1), flat-like oil (12.22 > S > 4.85) and film-like oil (S > 12.22). From CT scanning results, the method of water flooding can effectively unlock the type of block-like oil, while CH 4 flooding and CO 2 flooding can produce flat-like and film-like oil. Furthermore, CO 2 flooding can significantly unlock more film-like oil than CH 4 flooding.

In this article, a new method is proposed to quantificationally evaluate the effect of pore heterogeneity on the adsorption behavior of fluids in nanopores. First, the assumptions of furrowed, sinusoidal, and ravine pore surfaces are proposed to represent the heterogeneous nanopores in shale. Under the assumptions, a multicomponent potential theory of adsorption (MPTA) is coupled with Peng–Robinson equation of state (PR EOS) to model the adsorption behavior of hydrocarbons in nanopores. And, the geometrical and chemical heterogeneities in shale nanopores are, respectively, simulated by a spatial alteration and an amplitude deformation on potential energy. The fluid–fluid interaction is modeled by PR EOS, and the fluid‐pore wall surface interaction is simulated by a Steel 10‐4‐3 model for slit‐like nanopores and by a modified Lennard–Jones (LJ) 12‐6 model for cylindrical ones. Thereafter, the results of our theory are compared against the experimental data of shale rocks to validate its accuracy.

Nanopores in tight and shale reservoirs have been confirmed by numerous studies. The nanopores are not only the primary storage space of oil and gas, but also the main transport channels of confined fluids. Although considerable efforts have been devoted to study the confined behavior of hydrocarbon fluids in nanopores, most of them have a local smooth-surface assumption. The effect of pore heterogeneity is still lacking. In this paper, in order to effectively simulate the nanopore complexity, we propose the assumptions of furrowed surface and sinusoidal surface to represent the heterogeneous nanopores (or rough nanopores) in tight and shale rocks. Then, based on these assumptions, the multicomponent potential theory of adsorption (MPTA) is coupled with the Peng-Robinson equation of state (PR EOS) to investigate the behavior of hydrocarbon fluids in rough nanopores. In this theory, considering the different types of nanopore heterogeneity, the geometrical heterogeneity is modeled by a spatial deformation of the potential field, and the chemical heterogeneity is modeled by an amplitude deformation of this field. The fluid-fluid interactions are modeled by the PR EOS, and the fluid-surface interactions are modeled by a Steel 10-4-3 potential for slit-like nanopres and a modified Lennard-Jones (LJ) 12-6 potential for cylindrical nanopores. Then a prediction process for the behavior of methane, ethane, propane and their mixtures is performed. The results are compared against the experimental data of their adsorption isotherms from publishd literatures to validate the accuracy of the theory and process. Then, the effect of pore heterogeneity on the confined behavior of methane, ethane, propane is quantitatively studied. Results indicate that for the experimental data considered in this work, the theory for heterogeneous nanopores is capable of predicting the confined behavior of hydrocarbons in a wide range of pressure and temperature. The developed mathematical model can well predict the confined behavior of fluids both in slit-like and cylindrical nanopores. Compared with the results of a smooth pore surface, the geometrical heterogeneity can significantly affect the thermodynamic properties of hydrocarbon fluids, but the chemical heterogeneity cannot strongly distort the confined behavior of fluids. The effect of geometrical heterogeneity on the confined behavior of fluids mainly depends on the effective pore size. In hydrocarbon fluids, as the composition of heavy components increase, the effect of heterogeneity on the confined behavior of fluids is reduced. Also, as the nanopore size reduces, the effect of pore heterogeneity on the confined behavior of fluids is enhanced. For fluid mixture, compared with smooth surfaces, it is observed that for heterogeneous surface, the mole fraction of the heavy component in the vicinity of pore wall can increase significantly, and that of the light component is reduced. This investigation makes it possible to completely characterize the confined behavior of a confined fluid in heterogeneous nanopores.