Addressing the long-standing ambiguity in the design of plugging agent dosage for high-water-cut reservoirs—constrained by factors such as insufficient understanding of channeling pathways—this study leverages seepage mechanics theory and well test interpretation data. By investigating the synergistic mechanism between reservoir heterogeneity and plugging agent dosage, we clarified the synergistic control mechanism of the “dual resistance zones” between injection and production wells, and proposed a synergistic target framework: “reservoir heterogeneity—pressure and pressure gradient distribution—profile control to reconstruct the displacement system—dosage of particle and gel plugging agents.” On this basis, the determination criterion for the reasonable profile control radius was provided by systematically analyzing the relationship between the reasonable profile control radius and the development radius of advantage channel. We established dosage calculation models for plugging agents: the equivalent volume method (for particles) and the modified volume method (for gels), and developed a matching relationship between particle size (for particle plugging agents) and fracture aperture. Ultimately, a multi-dimensional synergistic design method for reasonable plugging agent dosage was proposed. Field application and subsequent follow-up evaluation studies have demonstrated that the plugging agent dosage designed by this method for target wells is 0.21~3.53 t/well for particles and 93.51~2399 m³/well for gels. After the implementation of profile control and water plugging measures, the pressure rise was reasonable, and the injection proceeded smoothly. The consistency between well test interpretation results and construction performance reached over 90%, achieving remarkable water control and oil stabilization effects. The research results provide technical support for water control and oil stabilization in high-water-cut reservoirs, and can improve the feasibility of profile control and water plugging design schemes for similar reservoirs by more than 30%.

Hydraulic fracturing operations can create complex fractures with spatiotemporal variations that significantly affect the transient rate performance of fractured wells. To address such heterogeneous fracture characteristics, the double-segment fracture model was adopted, allowing for distinct fracture conductivity and permeability modulus assignments to each fracture segment. A novel semi-analytical model was developed, validated, and applied to investigate the influence of non-uniform fracture properties on transient rate behavior for fractured wells. More specifically, the slab source function method and finite difference method were applied to solve the fluid flow problems in the matrix and fracture subsystems, respectively. The nonlinearity caused by the pressure-dependent fracture conductivity was tackled by the iteration method. Additionally, production type curves were constructed to assess the impact of non-uniform fracture properties on transient rate behavior. It is found that the fracture conductivity and stress-sensitivity of the fracture segment near the wellbore (FSNW) have a more significant impact on the well production rate than those of the fracture segment near the fracture tip (FSNT). As the fracture conductivity near the wellbore decreases, the production rate decreases correspondingly, whereas the fracture conductivity near the fracture tip has a negligible influence on the transient rate when fracture conductivity exceeds 10. The length of the fracture segment similarly affects the transient rate behavior, where longer high-conductivity fracture segments are associated with higher production rates. The stress-sensitivity of the FSNW greatly affects the transient rate, where higher stress-sensitivity levels result in a lower production rate. In contrast, the effect of stress-sensitivity of the FSNT on the transient rate can be neglected. The results and findings obtained in this work can help us analyze the practical production rate curves with more accurate approaches, thereby obtaining more reasonable and reliable estimation results of the fracture properties.

Due to the strong heterogeneity of the reservoir, early gas breakthrough and low CO₂ displacement efficiency are common issues in the CO₂ flooding process of domestic gravel reservoirs. This study focuses on a gravel reservoir in Xinjiang, proposing a quantitative evaluation method that combines early gas breakthrough identification and the inversion of gas channel characteristic parameters. The aim is to provide theoretical support and technical guidance for gas breakthrough risk warning, injection-production system optimization, and control measures during the CO₂ flooding process. The research method includes the following several key steps: first, clarifying the criteria for determining the time of gas breakthrough and proposing a classification method for early gas breakthrough types based on CO₂ concentration levels; second, adopting a “matrix-dominant gas channel” dual-medium model, considering the geometric and physical characteristics of inter-well gas channels, and deriving a theoretical calculation formula with gas breakthrough time and CO₂ concentration in the produced gas as the target; third, using actual gas breakthrough time and CO₂ concentration as constraints, constructing a method to invert the characteristic parameters of gas channels, quantitatively representing key parameters such as gas channel thickness ratio, permeability variation, and equivalent permeability; finally, through the combined analysis of CO₂ concentration and gas channel characteristic parameters, establishing a method for identifying gas channel types suitable for domestic gravel reservoirs. The practical application results show that the test area has formed localized dominant gas channels, but the overall stage is still in the early phase of weak gas breakthrough. Most gas breakthrough phenomena are weak, with only a few well groups experiencing severe gas breakthrough issues. The gas channel thickness ratio is generally less than 0.05, and the permeability variation mainly ranges from 2 to 20. The gas channels are primarily of the fracture type, with some areas also containing ordinary fractures and main control fractures. The method proposed in this study, which combines early gas breakthrough identification with the inversion of gas channel characteristic parameters, not only provides a new approach to revealing the characteristics of gas breakthrough during CO₂ flooding but also offers solid theoretical and technical support for optimizing CO₂ flooding technology and controlling gas breakthrough risks.