During the operation of commingled production wells, inter-layer interference is a key factor affecting the recovery rate and flooding extraction efficiency. This study proposes a well deliverability equation that is characterized by a multi-parameter coupled inter-layer interference coefficient, which is applied to quantify the commingled production wells in a multi-layer reservoir. This study used principal component analysis (PCA) to study the combined effects of correlation parameters for inter-layer interference. The results show that the starting pressure gradient and the crude oil viscosity contrast have the most significant impact on inter-layer interference. Changes in these two parameters directly enhance the heterogeneity between different oil layers, thereby intensifying inter-layer interference. Additionally, the positive correlation between permeability and permeability contrast also highlights the contribution of physical property differences in the oil layers to the interference. The sensitivity analysis shows the main influencing factors of inter-layer interference in commingled production wells. providing references for subsequent improvements and optimization of the exploitation schemes and adjustments in reservoir management measures. The results not only enhance the understanding of the mechanisms of inter-layer interference in the exploitation of multi-layer oil reservoirs but also provide scientific evidence and technical support for oilfield development.

To solve the development problems caused by the geological characteristics of heterogeneous sandstone reservoirs, such as uneven interlayer exploitation, a method for improving uneven interlayer exploitation differences by applying interlayer injection–production coupling technology is proposed. A physical model of interlayer injection–production coupling is elaborated in detail, and its mechanism of enhancing oil recovery is analyzed. The reservoir physical property parameters are measured, and a productivity numerical model for the two-phase flow of oil–water was established based on measurement results. Then, the effectiveness of interlayer injection–production coupling was evaluated. The results showed that the mechanism of interlayer injection–production coupling can be summarized as reservoir elastic energy adjustment and reservoir flow field reconstruction, based on the established physical model. The application of interlayer injection–production coupling technology can significantly improve the interlayer exploitation differences in strongly heterogeneous sandstone reservoirs. The injection rate, liquid production rate, half-period ratio, and coupling period all have a significant influence on the interlayer injection–production coupling effect. Specifically, for the J1 well group, the injection rate and liquid production rate can be appropriately increased by a factor of 2 and 1.5, and corresponding oil recovery will increase by 6.4% and 5%. Meanwhile, when the half-period ratio increases to 3:1, the oil recovery will increase by 7.08%. Therefore, during the design of the interlayer injection–production coupling scheme, the injection rate and liquid production rate can be appropriately increased, the injection time should be increased for the under-exploitation layer, and the optimal coupling period should be selected based on the characteristics of the oilfield.

There are currently numerous types of water-flooding characteristic curves, most of which are derived from fundamental theories such as material balance, relative permeability, along with experimental results. A single exponential or power function expression cannot accurately characterize the complex flow characteristics of different types of reservoirs, and the equivalent relationships corresponding to production wells and entire oilfields remain unclear. Consequently, practical applications often encounter issues such as curve tailing, difficulty in determining linear segments, inability to identify anomalous points, and inaccuracies in dynamic fitting and prediction. This paper derives a novel water-flooding characteristic curve expression based on fractal theory, incorporating the fractal characteristics of two-phase oil–water flow in reservoirs, as well as the micro-level pore–throat flow features and macro-level dynamic laws of water flooding. The approach is analyzed and validated with real oilfield cases. This study indicates that fitting with the novel water-flooding characteristic curve yields high correlation coefficients and excellent fitting results, demonstrating strong applicability across various types of oilfields and water cut stages. It can more accurately describe the water-flooding characteristics under different reservoir conditions and rapidly predict recoverable reserves, offering significant application value in the dynamic analysis of oilfields and the formulation of development strategies.

Waterflooding intensity strongly affects oil–water migration in deep-water sandstone reservoirs with bottom edge water, yet oil mobilization across different oil-occupied pore scales and the evolution of residual oil occurrence spaces under different waterflooding modes remain unclear. Constant high-rate and rate-increasing waterflooding experiments were conducted on deep-water sandstone cores. Online nuclear magnetic resonance (NMR) monitoring and fractal analysis were used to distinguish oil-occupied pore scale intervals from oil-phase $T_2$ signals and quantify the evolution of oil saturation and fractal dimensions under different waterflooding intensities. In 0–100 pore volumes (PV), rate-increasing waterflooding yielded slightly lower recovery than constant high-rate waterflooding. During 100–1000 PV, however, its recovery increment reached 8.68–12.39 percentage points versus 2.91–6.01 percentage points under constant high-rate waterflooding, increasing final recovery by 5.25–6.17 percentage points. Oil mobilization was dominated by macropore and mesopore intervals, with limited micropore mobilization. In 100–1000 PV, rate-increasing waterflooding caused larger oil saturation reductions in macropore and mesopore intervals (4.43–10.60 and 1.75–3.99 percentage points) than constant high-rate waterflooding (3.05–4.42 and 0.01–1.30 percentage points). Fractal dimensions increased during waterflooding, with the largest changes occurring in the micropore interval. Fractal dimension increments in mesopore and macropore intervals were 0.09–0.12 and 0.04–0.06 under rate-increasing waterflooding versus 0.04–0.07 and 0.03–0.05 under constant high-rate waterflooding. The results provide core scale insight into the relationship between injection history, late-stage oil depletion, and the $T_2$ distribution of remaining oil in deep-water sandstone.

Deepwater sandstone reservoirs are important hydrocarbon-bearing media and are prone to pore structure reconfiguration and seepage path evolution under long-term high-rate development conditions, which can significantly affect reservoir performance. However, their dynamic response mechanisms remain insufficiently understood. To address this issue, this study investigates the responses of deepwater sandstone reservoirs with different initial pore throat structures to prolonged high-rate water injection. Reservoir samples are first classified into three classes based on pore throat characteristics and fractal parameters derived from mercury intrusion capillary pressure (MICP) data. Representative cores are then subjected to long-term water injection, with permeability and pore structure evolution monitored up to 1000 PV. In situ nuclear magnetic resonance (NMR), together with scanning electron microscopy (SEM) and X-ray diffraction (XRD) observations before and after injection, is used to relate changes in flow capacity to multiscale pore redistribution and mineralogical–microstructural alteration. Pore sizes are quantified from the T₂ spectra, and fractal dimensions are calculated to characterize multiscale structural complexity. The results show that (1) the fractal parameters correspond closely to the pore throat structure and petrophysical properties. From Class I to Class III, the macropore throat fractal dimension generally increases, whereas the median pore throat radius, porosity, and permeability decrease. (2) During long-term high-rate water injection, permeability continuously decreases by 15.8–26.3%, accompanied by mineral redistribution, localized dissolution, and pore throat filling associated with fine-particle migration and retention. (3) Over the same injection period, the micropore fraction increases by 4.1–6.0%, whereas the macropore fraction decreases by 3.2–10.9%. The micropore fractal dimension increases markedly by 63.8–212.0%, whereas the changes in the mesopore and macropore domains remain limited to no more than 2.3%. Overall, the weakening of macropores, together with increasing heterogeneity in the micropore domain, progressively constrains effective flow pathways, resulting in sustained permeability decline and differentiated responses among reservoir classes.

Deepwater sandstone reservoirs are commonly developed under high-intensity injection and production conditions because of a limited number of wells, large injector–producer spacing, and offshore processing constraints. Injection rate variations alter the balance between viscous and capillary forces, thereby affecting oil–water displacement and remaining oil mobilization. However, the pore-scale effects of injection rate and rate adjustment sequence remain insufficiently understood. Here, a two-dimensional polydimethylsiloxane (PDMS) micromodel replicating the pore structure of a real deepwater sandstone reservoir was used to investigate four regimes: constant low-rate, constant high-rate, low-to-high-rate, and high-to-low-rate waterflooding. The low-to-high-rate regime achieved the highest final oil recovery factor of 88.41%, exceeding the constant low-rate, constant high-rate, and high-to-low-rate regimes by 6.54, 3.86, and 3.97 percentage points, respectively. Constant low-rate waterflooding gave the lowest recovery factor of 81.87% and a total areal remaining oil saturation of 18.13%, compared with 15.44% under constant high-rate conditions. Under low-rate flooding, wall-attached oil, elongated ganglia, and oil droplets accounted for 90.18% of the remaining oil, indicating limited mobilization of oil retained by interfacial effects and local capillary trapping. Increasing the rate reduced the total areal remaining oil saturation from 44.04% to 11.58%, mainly by mobilizing oil clusters and elongated ganglia, whereas decreasing the rate reduced it only from 16.52% to 15.55%. At the same cumulative injected volume of 1 PV, the total areal remaining oil saturation under high-rate flooding was 27.52 percentage points lower than that under low-rate flooding, indicating faster early-stage mobilization, while the low-rate stage retained more oil available for subsequent mobilization. These results show that waterflooding performance depends on both injection rate and flow history. A low-to-high-rate sequence combined relatively stable early-stage displacement with enhanced subsequent mobilization, providing pore-scale evidence that injection-rate history can influence displacement pathways and remaining-oil mobilization in deepwater sandstone reservoirs.