Due to the coexistence of multiple types of reservoir bodies and widely distributed aquifer support in karst carbonate reservoirs, it remains a great challenge to understand the reservoir flow dynamics based on traditional capacitance–resistance (CRM) models and Darcy’s percolation theory. To solve this issue, an improved injector–producer-pair-based CRM model coupling the effect of active aquifer support was first developed and combined with the newly-developed Stochastic Simplex Approximate Gradient (StoSAG) optimization algorithm for accurate inter-well connectivity estimation in a waterflood operation. The improved CRM–StoSAG workflow was further applied for real-time production optimization to find the optimal water injection rate at each control step by maximizing the net present value of production. The case study conducted for a typical karst reservoir indicated that the proposed workflow can provide good insight into complex multi-phase flow behaviors in karst carbonate reservoirs. Low connectivity coefficient and time delay constant most likely refer to active aquifer support through a high-permeable flow channel. Moreover, the injector–producer pair may be interconnected by complex fissure zones when both the connectivity coefficient and time delay constant are relatively large.

The flow field is the fluid dynamic flow path in strongly heterogeneous reservoirs, and its evolution significantly affects the distribution of remaining oil, showing a disordered and highly dispersed mode caused by long-time water injection. By combining traditional flow-field evaluation with flow diagnostics, this paper proposes a methodology to quantitatively characterize and adjust the flow field in real time during the late stage of waterflooding in strongly heterogeneous reservoirs. In the study, the fluid velocity, abundance of predominant remaining oil, and Lorenz coefficient are preferred as the characteristic parameters to evaluate the effect of reservoir and flow heterogeneity on the flow field. Taking the minimization of the Lorentz coefficient as the objective function, the optimal injection and production parameters are obtained by dynamic adjusting the flow field. The results show that as water injection continues, the shape and variation of the flow field are jointly influenced by the reservoir rhythm, vertical permeability contrast, and lateral permeability distribution. The larger the permeability contrast, the greater the influence of the lateral permeability distribution. When the permeability contrast is large, the Lorenz coefficient strongly depends on the lateral permeability distribution. Finally, this method is applied to an actual heterogeneous reservoir, and a better effect of oil increase and water reduction is achieved.

The spatial structural characteristics of fractured-vuggy units vary greatly in different karst patterns, which significantly influence the study of remaining oil distribution patterns in ultra-deep fractured-vuggy reservoirs and the determination of the most efficient development strategies. However, few numerical simulation studies have focused on improving water and gas injection in fractured-vuggy reservoirs by considering the effect of karst patterns. By taking a typical fractured-vuggy reservoir in C oilfield in Tarim Basin, China as an example, the development dynamic characteristics of eight typical fractured-vuggy units in three different karst patterns are analyzed, and based on the newly proposed numerical simulation method of fluid vertical equilibrium, the residual oil reservoir distribution in different karst pattern fractured-vuggy units are studied, and the effects of fracture-vuggy karst patterns on the development characteristics, on the remaining oil morphology pattern, on the development strategies, and on the injection-production parameters are explored. This study shows that for different karst patterns fractured-vuggy units, the complexity of spatial structure, reserve scale, and oil-water relationship aggravates the heterogeneity of reservoirs and results in substantial differences in the development of dynamic patterns. In the northern facing karst fractured-vuggy units, there are two main types of remaining oil: well-spacing type and local-blocking type, and the reasonable development strategies are affected by reservoir morphology and the connectivity of structure patterns. Attic-type remaining oil mainly occurs in platform margin overlay and fault-controlled karst fractured-vuggy units. In the southern fault-controlled karst area, the remaining oil is mostly found along the upper part, and periodic gas injection or N₂ huff-n-puff is recommended with priority for potential tapping. The fractured-vuggy karst patterns show a significant influence on the optimal level of injection-production parameters for improving the development of gas injection development strategies. The ideas of improving water injection and gas injection for fracture-vuggy reservoirs proposed in this paper also provide a good reference to further improve water control and increase oil production in other similar carbonate reservoirs.

Conventional hydrajet fracturing techniques are often frustrated when they are applied to some specific well types, such as casing-damaged and small-diameter wells. It is of great significance to investigate the erosion and stress on a small-diameter hydrajet fracturing tool during its service and clarify the relevant influencing factors. Based on the solid-liquid two-phase flow theory and erosion model, a numerical simulation was conducted on the erosion and stress on a small-diameter hydrajet fracturing tool by using the computational fluid dynamics approach in order to understand how the inlet flow rate, particle size, and particle mass concentration affect the erosion and stress on the tool. The results show that the erosion on the small-diameter hydrajet fracturing tool is generally a cutting erosion of proppant particles on the tool body. Such erosion occurs on the lower wall of the nozzle, and the erosion at the upper-0(degrees) nozzle is higher in rate and smaller in area than that at the lower-180(degrees) nozzle. The maximum stress of the small-diameter hydrajet fracturing tool is concentrated on the upper and lower walls of the upper and lower nozzles, especially the lower part inside the upper nozzle. The maximum erosion rate, average erosion rate, and maximum stress on the wall near the nozzle during fracturing increase as the inlet flow rate and particle mass concentration increase and decrease as the proppant particle size increases.

In the development of carbonate reservoirs via water flooding huff-n-puff, the osmotic pressure effect is frequently overlooked, and existing models inadequately quantify the matrix imbibition and oil expulsion driven by salinity gradients. To address this issue, this study establishes a coupled oil–water two-phase huff-n-puff flow model for carbonate reservoirs that incorporates the interplay between salt concentration and osmotic pressure, which, for the first time, fully couples the van ’t Hoff osmotic pressure equation with solute transport equations for fractured-vuggy carbonate huff-n-puff, filling the gap that prior tight/shale reservoir low-salinity flow models fail to adapt to cyclic injection-soaking production regimes of carbonates. Based on the IMPES (implicit pressure–explicit saturation) numerical simulation method, an equivalent single-nucleus model is adopted to characterize the fractured-vuggy reservoir architecture. The model integrates the osmotic pressure formula, solute transport equation, and two-phase seepage governing equations, enabling a systematic analysis of the mechanisms by which osmotic pressure affects the multi-stage seepage process and the influence of key parameters on development performance. Quantitative simulation reveals three core laws controlled by salinity-induced osmosis: first, osmotic pressure drives water molecules to spontaneously migrate from the high-permeability fracture inner core toward the tight matrix pores, thereby modifying the water saturation distribution, expanding the water sweep region, and smoothing the saturation gradient between the inner and outer cores, which effectively mitigates water channeling in fractured reservoirs. Under the base case (injected water salinity = 1000 mg/L, inner-core permeability = 1000 mD, shut-in time = 80 d), the oil recovery factor with osmotic pressure considered reaches 13.46%, representing a 3.50% increment over the case without osmotic pressure. The recovery factor decreases monotonically with increasing injected water salinity, while it increases with longer shut-in time and higher inner-core permeability, both exhibiting pronounced diminishing marginal returns; the optimal shut-in time is approximately 80 d under the simulated conditions. This work delivers a fully coupled numerical tool and quantitative evaluation standard for osmotic imbibition mechanisms in fractured-vuggy carbonates. The quantified recovery increment and optimal soaking window established herein can directly guide field parameter optimization of injection water salinity, shut-in cycle and fracture reconstruction scale, balancing oil increment revenue and water treatment/well shutdown operation costs for on-site low-salinity huff-n-puff design.

The relationship between two-phase flow behavior and pore microstructure in low-permeability gas reservoirs remains poorly understood, particularly during gas accumulation (gas displacing water) and subsequent development (water displacing gas). To address this, five plug cores with permeabilities ranging from 0.02 to 20.92 mD were selected from a low-permeability sandstone gas reservoir in the Tarim Oilfield. A comprehensive experimental program was carried out, including pore-throat structure characterization, wettability measurements, and both steady-state and unsteady-state gas–water relative permeability tests. These data were further integrated with capillary pressure curves derived from high-pressure mercury injection, centrifugation, and semipermeable membrane methods, enabling systematic comparison and parametric modeling. The results indicate that the reservoir is generally characterized by low permeability, fine pore throats, and moderate water-wetness, with contact angles between 49° and 60°. As permeability declines, pore-throat dimensions decrease and pore connectivity worsens: the mercury injection saturation median pressure increases from 0.752 to 16.477 MPa, while mercury withdrawal efficiency drops from 78.59% to 40.54%. These trends suggest that finer throats impose greater resistance to nonwetting phase invasion and that the “ink-bottle” effect intensifies fluid entrapment. Relative permeability measurements show that the unsteady-state method is more responsive to gas breakthrough and localized flow channeling, yielding lower endpoint gas relative permeability compared to the steady-state approach. With deteriorating reservoir quality, irreducible water saturation during gas displacement rises from 29.03% to 45.20%, residual gas saturation during water displacement increases from 17.60% to 38.90%, and the two-phase coexisting flow zone narrows markedly from 53.37% to 15.90%. The consistent trends observed between relative permeability and mercury injection data confirm that reduced pore-throat size and heightened capillary resistance not only hinder the formation of continuous nonwetting phase pathways but also promote water retention and gas trapping. Through normalization, representative Corey-type gas–water relative permeability curves were established for the study area (with Corey exponents of 2.393 and 1.534 for the gas and water phases, respectively, under gas-displacing-water conditions), along with Brooks–Corey-type capillary pressure curves (with equivalent displacement pressures ranging from 0.025 to 0.133 MPa). These results provide essential parameters for seepage characterization and numerical simulation of underground gas storage in low-permeability gas reservoirs.