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After multi-stage volume hydraulic fracturing in a shale oil reservoir, massive amounts of water can be imbibed into the matrix pores. One of the key imbibition characteristics of a shale reservoir is the imbibition water and its height distribution. Based on high pressure mercury injection (HPMI) experiments and nuclear magnetic resonance (NMR) analyses, this study quantitatively evaluated the pore-size distribution of Chang 7 continental shale oil reservoirs in Yanchang Formation, Ordos Basin. The pores could be divided into three types as micropores (≤0.1 μm), mesopores (0.1–1.0 μm), and macropores (>1.0 μm), while the volume of micropores and mesopores accounted for more than 90%. This demonstrated that there were strong heterogeneity and micro–nano characteristics. According to the spontaneous imbibition (SI) experiments, the cumulative proportion of imbibition water content was the largest in micropores, exceeding 43%, followed by mesopores around 30%, and that of macropores was the lowest, and basically less than 20%. The negative values of stage water content in the macropore or mesopore indicated that these pores became a water supply channel for other dominant imbibition pores. Additionally, combining the fractal theory with the NMR T2 spectrum, the relative imbibition water and actual height were calculated in different pores, while the height distribution varied with cores and shale oil. The shorter the core, the higher was the relative height, while the radius of macropores filled with imbibition water was reduced. This indicates that the height distribution was affected by the pore structure, oil viscosity, and core length. [ABSTRACT FROM AUTHOR]

Polymer microspheres (PMs) are used as a new material to recover residual oil left in unswept oil areas after secondary recovery methods. The fact that the PMs plug the macropores causes the flow direction of the injection fluid to be transferred from macropores to micropores. In order to investigate the plugging and profile control mechanisms of PMs in reservoirs, four kinds of PMs with different particle sizes and four kinds of artificial cores with different permeability were selected for flooding tests, including plugging experiments and profile control experiments. The pore throat size distribution of cores was characterized by nuclear magnetic resonance (NMR) technology. The particle size distribution of PMs used in the experiment was characterized using a laser particle size analyzer. The results showed that there are six matching relationships existing simultaneously between pore throats and PMs based on theoretical analysis, which are completely plugging, single plugging, bridge plugging, smooth passing, deposition, and deformable passing. A key principle for optimizing PMs in profile control is that the particle size of the selected PMs can enter the high permeability layer well, but it is difficult for it to enter the low permeability layer. The results of this paper provide a theoretical basis for the optimal particle size of PMs during the oil field profile control process. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition of water into tight oil reservoirs is considered an effective way to improve tight oil recovery. We have combined testing techniques such as nuclear magnetic resonance, mercury injection capillary pressure, and magnetic resonance imaging to reveal the distribution characteristics of oil and water during the spontaneous imbibition process of tight sandstone reservoir. The experimental results were used to describe the dynamic process of oil–water distribution at the microscopic scale. The water phase is absorbed into the core sample by micropores and mesopores under capillary forces that dry away the original oil phase into the hydraulically connected macropores. The oil phase entering the macropores will drive away the oil in place and expel the original oil from the macropores. The results of magnetic resonance imaging clearly show that the remaining oil accumulates in the central region of the core because a large amount of water is absorbed in the late stage of spontaneous imbibition, and the water in the pores gradually connects to form a "water shield" that blocks the flow of the oil phase. We propose the spontaneous imbibition pathway, which can effectively explain the internal mechanisms controlling the spontaneous imbibition rate. The surface of the core tends to form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is fast. The deep core does not easily form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is slow. This paper reveals the pore characteristics and distribution of oil and water during the spontaneous imbibition process, which is of significance for the efficient development of tight oil. [ABSTRACT FROM AUTHOR]