Abstract: The tight reservoirs are characterized by low porosity, low permeability, as well as a complex interplay among pores, natural fractures, and artificial fractures. It is generally believed that spontaneous imbibition caused by capillary action is the primary driving force for oil displacement in tight reservoirs. However, variations in the water phase salinity within the reservoir can trigger more complicated imbibition-osmosis coupling effects, making it evident that the true flow characteristics of oil and water phases in the reservoir cannot be adequately explained only through imbibition mechanisms. Therefore, a systematic study was performed on the oil-water flow characteristics in tight reservoirs induced by salinity changes. Firstly, the impact of salinity on interfacial tension (IFT) and contact angle was investigated, followed by a quantitative analysis of the imbibition dynamics and efficiency under varying salinity conditions. Subsequently, the fluid flow in tight reservoir cores induced by salinity changes were characterized using improved imbibition-osmosis experiments. Combined with theoretical analysis, the study reveals the underlying mechanisms of osmosis flow and imbibition-osmosis coupling effect, and preliminarily probes into the contributions of the fluid flow caused by salinity variation between the inner and outer core to oil displacement efficiency. The experimental results indicate that as the salinity increases, the hydrophilicity of rock enhances. Additionally, the salinity variation between the internal and external water phases of the rock matrix also affects the contact angle. With an increase in salinity, the oil-water IFT initially keeps stable, then increases rapidly, and finally stabilize again. Furthermore, with the increasing of salinity, the imbibition-based oil displacement efficiency first increases and then decreases, peaking at 17.42 % when the salinity reaches 1×10⁵mg/L. The salinity gradient between the internal and external water phases within the rock core can induce an osmosis effect that triggers the flow of water and oil. When the internal salinity level of a core sample exceeds the external level, the core undergoes a "re-absorption" phenomenon, known as "forward osmosis". In contrast, when the internal salinity level is lower than the external level, the core exhibits a "water expulsion" phenomenon, referred to as "reverse osmosis". Forward permeation can significantly enhance oil recovery, achieving a 33.14 % to 48.66 % contribution to the total recovery. For tight reservoirs, the goal of high-efficient development can be realized through reasonable adjustment of the aqueous salinity.

Key words: tight oil, osmosis flow, imbibition-osmosis coupling mechanism, oil recovery, water salinity

摘要： 致密储层具有低孔、低渗、孔隙—天然裂缝—人工裂缝关系复杂等特点,通常认为毛细管引起的自发渗吸是该类储层的主要驱油动力。但储层中水相矿化度的变化,会引发更为复杂的渗吸—渗透耦合作用,仅通过渗吸机理显然无法清楚地解释储层真实油水相流动特征。为此,对矿化度变化引发的致密储层油水流动特征进行了系统研究。首先,研究了矿化度对界面张力和接触角的影响;其次,量化分析了不同矿化度下渗吸动态及效率;然后,利用改进的渗吸—渗透实验,明确了矿化度改变引发的岩心渗透流动特征;最后,结合理论分析揭示了渗透流 动机理及渗吸—渗透耦合作用机理,初步探索了岩心内外矿化度差引起的渗透流动对驱油效率的贡献程度。实验结果表明:随着矿化度增大岩石的亲水性增强,且岩石基质内部与外部水相矿化度差也会对接触角产生影响;矿化度增大,油水界面张力呈稳定、快速增大、稳定的三段式变化特征;渗吸驱油效率随矿化度的升高先增大后降低,矿化度为1×10⁵mg/L时驱油效率最大(17.42 % );岩心内外水相矿化度差导致的渗透作用会引发水相和油相的流动;当岩心内部矿化度高于外部时,岩心会发生二次吸水现象,称为正向渗透;反之,岩心会发生"吐水"现象,称为反向渗透。岩心的正向渗透可以大幅度提高采收率,渗透阶段贡献率可达33.14 % ~48.66 % 。对于致密储层,可通过水相矿化度 的合理调整,达到高效开发的目的。

关键词: 致密储层, 渗透流动, 渗吸—渗透耦合机理, 采收率, 水相矿化度