With the large-scale application of profile control and water shutoff technology in the oil reservoir development process, high-water-cut oil reservoirs face a core challenge during the profile control and water shutoff process: the balance mechanism between the selective plugging of high-permeability channels by gel particles and the residual seepage capacity remains unclear. In particular, there is a lack of quantitative characterization methods for the multiscale coupling effects between gel particles and porous media, which leads to inaccurate cross-scale coordinated regulation of plugging strength and flow conductivity and further causes engineering problems such as plugging agent channeling failure and excessive plugging. In response to this, based on the theory of seepage mechanics, this study takes the pore-throat structure of medium–high-permeability/low-permeability reservoirs as the prototype and establishes a multiscale physical and mathematical model for the dynamic plugging of gel particles in annular seepage channels. Through theoretical derivation and boundary condition verification, the global analytical solutions for the axial seepage velocity field v _z (r), seepage flow rate Q, effective permeability K, and seepage resistance R _f were obtained. This study quantitatively reveals the nonlinear regulation law of the gel particle radius r _c and pore-throat size ratio λ = r _c/R (where R is the pore-throat radius) on seepage parameters and clarifies the formation mechanism of micronano-scale residual seepage channels. The results show that gel particles form local plugging bodies through the synergistic effect of deformation and jamming, and the gap between these plugging bodies and the pore-throat wall constitutes the residual seepage channel. When λ ∈ [0.4, 0.8], the seepage resistance R _f increases nonlinearly sharply (with an increase of 2–5 orders of magnitude), while the permeability K decays following a power-law rule dominated by R ⁴. This study establishes a quantitative characterization method for the action mechanism of gel particles from the microscopic scale and constructs a correlation model between plugging agent parameters and seepage response, thereby providing a theoretical basis for the particle size optimization of profile control and water shutoff systems in heterogeneous reservoirs, as well as the design of balance between plugging and flow conductivity.

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%.

WAG flooding is a dynamic process of continuous reservoir flow field reconstruction. The unique advantages of WAG flooding cannot be utilized, due to the fixed water–gas ratio. Therefore, we must investigate the dynamic adjustment of the water–gas ratio for WAG flooding. Using nine cases of long-core displacement experiments in low-permeability reservoirs, the development effects of three different displacement methods, namely, continuous gas flooding, WAG flooding with a fixed water–gas ratio, and WAG flooding with a dynamic water–gas ratio, were investigated after elastic development, water flooding, and gas flooding. This study shows that for early elastic development in low-permeability reservoirs, WAG flooding can significantly improve oil recovery, but WAG flooding with a dynamic water–gas ratio is not conducive to the control of the water cut rise and gas channeling. As a result, it is more suitable to adopt WAG flooding with a fixed water–gas ratio. For early water flooding in low-permeability reservoirs, WAG flooding more clearly improves oil recovery and suppresses gas channeling, but WAG flooding with a dynamic water–gas ratio exhibits a higher oil recovery and thus is recommended. For early gas flooding in low-permeability reservoirs, whether the development effect of WAG flooding can improve oil recovery and inhibit gas channeling strongly depends on whether the water–gas ratio is adjusted. The development effect of WAG flooding with a dynamic water–gas ratio is significantly better than that with a fixed water–gas ratio. Therefore, WAG flooding with a dynamic water–gas ratio is recommended to achieve the best displacement effect. This research has important practical significance for further improving the development effect of WAG flooding in low-permeability reservoirs.

Against the backdrop of global energy pattern restructuring, the advancement of dual-carbon goals and large-scale development of unconventional oil and gas, complex oil and gas fields are confronted with practical challenges including harsh geological conditions and diversified development objectives. Traditional development planning methods for oil and gas fields suffer from single evaluation dimensions, strong subjectivity in decision making and insufficient dynamic adaptability, which make them unable to meet the full-process development requirements. To realize scientific, quantitative and systematic development planning of complex oil and gas fields, a development planning evaluation method suitable for complex oil and gas fields is established by integrating multidisciplinary theories. First, a multilevel evaluation model for oil and gas field development planning is constructed according to the characteristics and difficulties of development planning evaluation for complex oil and gas fields. The model consists of five core modules: external analysis, internal analysis, corporate development strategy selection, business planning and risk assessment. Secondly, a development planning evaluation method is established through a closed-loop process including special quantitative IFE/EFE analysis, IE matrix strategic positioning, SWOT alternative strategy pool and QSPM priority ranking. Then, the strategic priority ranking is dynamically adjusted by considering the impact of stepped oil prices. Finally, combined with the analytic hierarchy process (AHP), a comprehensive risk index evaluation model is established to realize quantitative assessment and traceability of risk levels. A case application in Block M demonstrates that its strategic positioning belongs to the growth type. Under low–medium–high tiered oil prices, the strategic combinations with the highest strategic priority are W+O strategy, S+O strategy and S+O, respectively. The development risk level is moderate risk. This study fills the gap in the whole-process evaluation system of complex oil and gas fields, and realizes the transformation of development planning from qualitative analysis to quantitative decision making. It provides theoretical methods and practical references for ensuring high-quality development of complex oil and gas fields and energy security.

To address the characteristics of strong heterogeneity, complex pore-throat structures, and poor adaptability of conventional flooding systems in conglomerate reservoirs, a systematic comparative study on the oil displacement efficiency of middle-phase microemulsion and conventional binary systems (polymer + surfactant) was conducted using a combination of long-core displacement experiments, interfacial tension measurements, and polarizing microscopy observations. Representative cores with permeability ranging from 50 to 500 mD were selected for displacement experiments under varying conditions of injection rate, permeability contrast, timing of chemical injection, and surfactant concentration. A three-stage experimental procedure comprising waterflooding, chemical flooding, and post-waterflooding was employed to compare and analyze the injectivity, enhanced oil recovery (EOR) magnitude, and water control performance of the two flooding systems. The results indicate that the middle-phase microemulsion exhibits significantly superior oil displacement efficiency compared to the binary system across the entire permeability range. It demonstrates excellent injectivity in medium-permeability reservoirs above 50 mD, rapidly achieving an ultra-low interfacial tension on the order of 10–3 mN/m, which effectively mobilizes residual oil trapped in fine pore throats. The final enhanced oil recovery increment is 3–7 percentage points higher than that achieved with the binary system. The applicability boundaries for middle-phase microemulsion flooding are defined as follows: permeability should not be lower than that of conventional low-permeability reservoirs; injection conversion is preferably implemented during the high water-cut stage; the permeability heterogeneity ratio should not exceed 10. Additionally, supporting measures for channeling control are required to accommodate reservoir stress sensitivity. The middle-phase microemulsion effectively inhibits water channeling, and its stability and profile control capability are significantly superior to those of the binary system. The research findings provide technical support and a theoretical basis for enhanced oil recovery in conglomerate reservoirs and analogous highly heterogeneous reservoirs.