In the drilling process of ultra-deep wells with large-diameter boreholes, the transport and deposition behavior of cuttings plays a critical role in maintaining wellbore cleanliness and ensuring operational safety. Due to the geometry of enlarged boreholes and their complex annular flow characteristics, conventional single-parameter control methods often fail to achieve effective cuttings transport. This study aims to identify the dominant influencing factors and optimize key parameters by focusing on the cuttings volume fraction as a primary evaluation metric. A numerical simulation approach is employed to systematically investigate the influence of stabilizer geometry and hydraulic parameters. Five variables—drilling fluid velocity, drill pipe rotational speed, number of stabilizers, flow area, and helical angle—are selected for analysis. An initial one-factor sensitivity analysis is conducted to evaluate local impacts and to establish relative sensitivity indices, thereby identifying key variables. A variance-based global sensitivity analysis is further applied to quantify first-order effects, full-order effects, and interaction contributions, revealing nonlinear coupling and synergistic mechanisms. The results indicate that drilling fluid velocity and rotation speed exhibit the most significant first-order influences, while stabilizer-related parameters show strong interaction effects that are often underestimated by traditional methods. Based on these findings, an optimized cuttings transport scheme for large-diameter boreholes is proposed. Additionally, a multi-parameter response model for the cuttings volume fraction is developed using sensitivity-weighted analysis, offering theoretical support and methodological reference for enhancing cuttings transport performance and structural design in large-diameter borehole drilling operations.

The deposition of large-sized cuttings (or blocky cuttings) is a critical risk factor for stuck pipe incidents during the drilling of deep and extended-reach wells. This risk is particularly pronounced in well sections with long borehole trajectories and low drilling fluid return velocities, where it poses a substantial threat to wellbore cleanliness and the safe operation of the drill string. This study utilizes a self-developed visual experimental platform to simulate the deposition evolution of large-sized cuttings (20–40 mm in diameter) in the annulus under various wellbore inclinations and drilling fluid parameters. The stable height, lateral distribution characteristics, and response patterns of the resulting cuttings bed under different conditions were quantitatively characterized. Building upon this, a theoretical contact friction model between the drill string and the cuttings bed was employed to investigate how the bed height influences hook load during tripping and rotary torque during top drive operation. A mapping relationship was established between cuttings bed structural parameters and the resulting additional loads and torques. Results reveal significant interactive effects among drilling fluid velocity, fluid density, drill pipe rotation speed, and wellbore inclination on both cuttings bed development and associated drill string loads. Strong correlations were identified among these parameters. Based on these findings, a stuck pipe early-warning indicator system is proposed using frictional load thresholds, with clearly defined safety limits for cuttings bed height. Recommendations for optimizing cuttings transport parameters through coordinated control of fluid velocity, density, and rotary speed are also provided, offering theoretical support and engineering guidance for borehole cleaning strategies and stuck pipe risk prediction in large cuttings scenarios.

With growing reliance on hydraulic fracturing to develop tight oil and gas reservoirs characterized by low porosity and permeability, optimizing proppant transport and placement has become critical to sustaining fracture conductivity and production. However, how fracture geometry influences proppant distribution under varying field conditions remains insufficiently understood. This study employed computational fluid dynamics to investigate proppant transport and placement in hydraulic fractures of which the aperture tapers linearly along their length. Four taper rate models (δ = 0, 1/1500, 1/750, and 1/500) were analyzed under a range of operational parameters: injection velocities (1.38–3.24 m/s), sand concentrations (2–8%), proppant particle sizes (0.21–0.85 mm), and proppant densities (1760–3200 kg/m³). Equilibrium proppant pack height was adopted as the key metric for pack morphology. The results show that increasing injection rate and taper rate both serve to lower pack heights and enhance downstream transport, while a higher sand concentration, larger particle size, and greater density tend to raise pack heights and promote more stable pack geometries. In tapering fractures, higher δ values amplify flow acceleration and turbulence, yielding flatter, “table-top” proppant distributions and extended placement lengths. Fine, low-density proppants more readily penetrate to the fracture tip, whereas coarse or dense particles form taller inlet packs but can still be carried farther under high taper conditions. These findings offer quantitative guidance for optimizing fracture geometry, injection parameters, and proppant design to improve conductivity and reduce sand-plugging risk in tight formations. These insights address the challenge of achieving effective proppant placement in complex fractures and provide quantitative guidance for tailoring fracture geometry, injection parameters, and proppant properties to improve conductivity and mitigate sand plugging risks in tight formations.

The small-spacing dual-well (SSDW) technique plays a crucial role in the establishment of underground salt cavern gas storage reservoirs. However, during the cavity dissolution and brine discharge processes, insoluble sediment is prone to being carried into the discharge tubing with the brine, leading to tubing blockages or clogging, which disrupts injection and withdrawal operations and severely affects both project efficiency and the safety of the gas storage facility. This study systematically analyzes the influence of the gap between the injection and discharge tubing and the surface of the sediment-on-sediment movement, deposition, and tubing safety in SSDW salt caverns. Through numerical simulations, this study investigates the influence of tubing layout on the internal flow field distribution of the cavern and the suspension behavior of sediment, revealing the changing trend of the risk of sediment entering the tubing at different distances. The results show that a rational tubing distance can significantly lower the risk of sediment backflow and tubing entry, while maintaining high brine discharge efficiency. Based on the simulation results, an optimized tubing layout design suitable for SSDW salt caverns is proposed, offering technical direction to guarantee the safe and effective functioning of underground salt cavern gas storage sites.

Exploitation of deep (>4000 m) tight geothermal reservoirs is constrained by low native permeability and premature thermal breakthrough, limiting sustainable heat recovery. Here, we investigate THM (thermo–hydro–mechanical) controls on fluid flow and heat transport during cold-water reinjection in deep tight sandstone reservoirs through an integrated framework linking two-dimensional mechanistic analysis with three-dimensional field-scale modeling. A two-dimensional thermo-poroelastic model reveals that strong thermal contrasts induced by cold-fluid injection cause contraction of the rock framework and transient pore-space dilation under confinement, producing short-term permeability enhancement. This process alters local flow capacity and redirects early cold-front migration, with persistent impacts on subsequent heat transport. Field-scale simulations further quantify the coupled effects of well spacing and reinjection temperature on thermal breakthrough, defined as a 1 °C decline in production-well temperature. Increased well spacing delays cold-front arrival and significantly retards breakthrough, whereas lower reinjection temperature enhances early heat extraction but accelerates convective transport, leading to earlier breakthrough. The combination of thermally enhanced permeability and intensified convection promotes preferential flow channels, increasing breakthrough risk. Balancing thermal-breakthrough delay against the heat-extraction driving force, the simulations delineate a favorable engineering window for the investigated conditions and clarify how cooling-sensitive permeability evolution affects preferential flow and reservoir-scale thermal response.