As an effective technology for enhancing oil recovery, low-salinity water flooding requires further investigation into its microscopic displacement mechanisms and the regulatory roles of key ions. Based on microscopic visualization displacement experiments, this study systematically investigated the effects of injected water salinity, key ion types (Na⁺, K⁺, Ca²⁺, Mg²⁺, HCO₃⁻, CO₃²⁻, SO₄²⁻, and OH⁻), and their concentrations on crude oil displacement behavior in both high- and low-permeability zones. Experimental results indicate that no significant correlation exists between displacement efficiency and injected water salinity in high-permeability zones. In low-permeability zones, displacement efficiency increases with decreasing salinity, peaking at 26.5% when injected water salinity reaches 5000 mg/L. The cation displacement efficiency in the formation, from highest to lowest, is Ca²⁺ > K⁺ > Mg²⁺ > Na⁺. The anion displacement efficiency, from highest to lowest, is OH⁻ > SO₄²⁻ > CO₃²⁻ > HCO₃⁻. When the CaCl₂ concentration decreased from 100 wt% to 50 wt%, the displacement effect in the low-permeability zone improved further, indicating that a higher concentration of the divalent cation Ca²⁺ is not necessarily better. In medium-to-high salinity formation water reservoirs, and under conditions where the influence of clay minerals is disregarded, ion type and reservoir permeability are the most significant factors affecting oil recovery efficiency. These findings provide theoretical support for elucidating the micro-dynamic mechanisms of low-salinity water flooding in low-permeability zones and optimizing injection water formulations.

Hydraulic fracturing is considered as an effective approach for the development of tight oil reservoirs. Unlike conventional reservoirs, after a large volume injection of the fracturing fluid, the flowback rate in tight oil reservoirs is considerably lower whereas the underlying mechanism explaining water retention remains unclear. Therefore, in this work, to investigate the water retention mechanism, fracturing fluid injection and particularly oil production process were emulated within real tight rock chips. Displacement and water retention events were directly visualised and captured using a microscope. As a result, the discrepancy between temporary and permanent residence of water inside the pore space was clarified. Additionally, nuclear magnetic resonance (NMR) scanning was incorporated to study the pore-scale fluid flow behaviours. Results show that a large portion of water was retained in smaller pores and water retention rate is positively correlated with oil recovery, implying invaded water replaced the oil and resided in the pore space therefore increasing the mobile oil in the formation as oil flowing back. This work proposed an interpretation of water retention mechanism in tight oil reservoir after hydraulic fracturing and provided an insight to optimise the development and production of tight oil reservoirs. [Received: January 20, 2020; Accepted: April 23, 2020]

“Fracture network stimulation + imbibition replacement” is a new attempt to effectively develop tight sandstone reservoirs, and the fractures provide conditions for fluid imbibition replacement. On the basis of nuclear magnetic resonance and pseudo-color processing technology, combined with the imbibition experiments, this paper studies the imbibition process of fractured tight sandstone reservoirs, clarifies the effect of each level of pore-throat on imbibition, and realizes the visualization of the imbibition process. The results show that, in fractured tight sandstone reservoirs, the fluid displacement occurs in fractures first, followed by pore-throat. Most of the imbibition recovery is contributed by the macropore, the contribution of the mesopore to imbibition recovery is very weak, and the contributions of the micropore and the pinhole are even less. In the process of imbibition, capillary force and gravitational force are key parameters controlling fluid flow in pores and fractures. The replacement of fluid normally takes place in the early stage of imbibition, especially on the first day of imbibition, then the imbibition rate gradually decreases and finally tends to be stable.

Horizontal-well multi-cluster fracturing is one of the most important techniques for increasing the recovery rate in unconventional oil and gas reservoir development. However, under the influence of complex induced stress fields, the mechanism of interaction and propagation of fractures within each segment remains unclear. In this study, based on rock fracture criteria, combined with the boundary element displacement discontinuity method, a two-dimensional numerical simulation model of hydraulic fracturing crack propagation in a planar plane was established. Using this model, the interaction and propagation process of inter-cluster fractures under different fracturing sequences within horizontal well segments and the mechanism of induced stress field effects were analyzed. The influence mechanism of cluster spacing, fracture design length, and fracture internal pressure on the propagation morphology of inter-cluster fractures was also investigated. The research results indicate that, when using the alternating fracturing method, it is advisable to appropriately increase the cluster spacing to weaken the inhibitory effect of induced stress around the fractures created by prior fracturing on subsequent fracturing. Compared to the alternating fracturing method, the propagation morphology of fractures under the symmetrical fracturing method is more complex. At smaller cluster spacing, fractures created by prior fracturing are more susceptible to being captured by fractures from subsequent fracturing. The findings of this study provide reliable theoretical support for the optimization design of fracturing sequences and fracturing processes in horizontal well segments.

To address the insufficient consideration of osmotic pressure in existing studies on water huff-and-puff in tight oil reservoirs, this paper introduces both osmotic and capillary pressures into two-phase flow theory and develops a full-cycle model for low-salinity water injection. The effects of salinity, injection rate, and soaking time on pressure, saturation, and salt concentration are analyzed. Results show that lower salinity enhances osmotic drive and improves recovery. Specifically, 1000 mg/L yields the highest recovery (10.94%) and an osmotic gradient of ~3.9 MPa. Capillary pressure acts synergistically with osmotic pressure during the soaking stage, promoting spontaneous imbibition and fluid redistribution. An optimal injection rate exists: excessive rates reduce swept volume, while very low rates prolong the cycle. Quantitatively, 80 m³/d is preferred (recovery 10.94%) over 40 m³/d (11.13%) as it halves the injection time with comparable recovery. There is also an optimal soaking time beyond which incremental gain diminishes. Recovery rises from 9.32% at 20 d to 10.94% at 40 d, with only 0.28% and 0.20% gains afterward; thus, 40 d is optimal. The model captures osmotic-driven behavior and reveals the secondary displacement effect during soaking, supporting parameter optimization.

“Fracture network stimulation and oil-water infiltration and replacement” are recent attempts to effectively produce oil from tight reservoirs. On the one hand, the formation can be fractured by the fracturing fluid, which can carry proppant into fractures. On the other hand, the fracturing fluid can spontaneously infiltrate into the pores under the action of capillary pressure to displace the oil phase, thereby enhancing the oil recovery. To distinguish imbibition and displacement processes during fluid replacement in tight reservoirs is difficult, and the effect of these two processes is also vaguely defined. In this study, an experimental method that can visualize the imbibition and displacement process is proposed by combining the core slice displacement experiment. Based on this method, the process of imbibition and displacement can be effectively distinguished, and imbibition retention rate can be quantitatively characterized. The effectiveness of this method is proved by taking the core of Chang 7 tight sandstone reservoir in the Ordos Basin as the research object. The results show that the force direction of the fluid under imbibition is related to the wettability, and it is always from the wetting phase to the nonwetting phase, while the force direction of fluid under displacement is mainly related to the directivity of displacement pressure difference. Based on the difference of force action, imbibition and displacement can be quantitatively characterized, respectively. During the imbibition process, the peak value of the NMR curve corresponding to the small pore throat shifts to the left, and the signal amplitude increases. During the displacement process, the peak value of the NMR curve corresponding to the small pore throat has no obvious shift, nor signal amplitude change, but the peak value of the curve corresponding to the large pore throat shifts to the right. The results also indicate that there is an exponential negative correlation between imbibition retention rate and gas permeability. The greater the gas permeability is, the smaller the imbibition retention rate is.