Prolonged water injection in unconsolidated sandstone reservoirs can induce pore rearrangement and modify flow pathways, thereby affecting reservoir performance. However, quantitative characterization of pore evolution in both temporal and spatial dimensions remains limited. This study investigates the mechanisms of pore-structure evolution during extended injection through a series of multi-scale experiments. Scanning electron microscopy and X-ray diffraction analyses were employed to compare mineral composition and microstructural characteristics before and after injection, while in situ nuclear magnetic resonance (NMR) monitoring captured the dynamic evolution process, enabling pore-size classification from T₂ spectra and fractal assessment of structural complexity. Segmented NMR measurements at different distances further resolved spatial heterogeneity. The results show that prolonged water injection reduced permeability by 10.4–32.1%, whereas porosity exhibited only minor variation, indicating that the decline in flow capacity is primarily controlled by pore–throat structural adjustment rather than pore volume loss. Mineralogical redistribution and fine-particle migration decreased the median pore radius by 21.5–51.8% and the micropore fractal dimension by 23.8–76.5%, with stronger responses observed at higher permeabilities, while meso- and macropore fractal dimensions remained nearly unchanged, indicating preferential modification of micropores with preservation of the main connected flow framework. Consistently, NMR responses reveal pronounced spatial heterogeneity along the flow direction. The NMR signal changes at the injection end were 11.2–18.4% and 7.7–21.7% during the early and intermediate stages, respectively, both exceeding those at the distal end (2.9–12.4% and 1.9–17.1%). These results indicate a downstream-attenuating structural modification gradient. The findings provide new insights into pore-structure evolution during prolonged water injection and offer a scientific basis for optimizing water-injection strategies in unconsolidated sandstone reservoirs.

The influence of various factors, such as the natural properties of rock and in-situ stress conditions, results in uneven and rough fracture surfaces post-hydraulic fracturing. This significantly impacts the transport and placement of proppant within the fracture, thereby affecting the effectiveness of fracture stimulation. This study employs the rectangular wave method to characterize the roughness of fracture wall morphology, detailing the variation of roughness by altering the number and height of micro-protuberances, and constructs a three-dimensional model of rough fractures. The Euler–Euler model is utilized to simulate the placement and transport patterns of proppant within the fracture. Sand banks within the fracture profile are segmented based on proppant concentration, and the dimensionless area of each concentration interval is calculated to analyze the structure of sand banks and the suspension and settling effects of proppant. This research investigates the variation patterns of sand dune structures within fractures characterized by different levels of roughness and morphologies; it also examines the impact of injection velocity and fracturing fluid viscosity on the transport and placement of proppant within rough fractures. The findings indicate that the complex spatial structure of rough fractures modifies the edge shape of sand dunes. Moreover, it impedes proppant transport, leading to the formation of sand plugs near the wellbore. The maximum distance of sand placement for rough fractures is only 55.2% of that for fractures without considering roughness. The increase in the number and height of micro-protrusions enhances fracture roughness, leading to a stronger retarding effect. However, variations in these two types of roughness have distinct impacts on the morphology of sand dunes. Higher injection velocities facilitate the transport of proppant within rough fractures. The furthest distance of proppant placement at an injection velocity of 0.5 m³/min is only 68.4% of that at an injection velocity of 1.5 m³/min. The study’s findings contribute to a more intuitive understanding of the impact of rough fracture wall surfaces on the transport and placement patterns of proppant, providing a foundation for the optimization of fracturing design and operational parameters.

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.