The low-velocity non-Darcy effect within the shale matrix significantly influences the well production performance of shale reservoirs, primarily caused by the threshold pressure gradient identified by various researchers. Moreover, in inter-salt shale reservoirs, salt minerals dissolve and diffuse when they encounter water-based working fluids, resulting in substantial alterations in pore structure. This paper introduces a transient pressure model for inter-salt shale oil reservoirs that accounts for oil flow from formation to the wellbore, considering all of the aforementioned mechanisms. The partial differential equations of this dual-porosity model, which incorporate salt dissolution and the low-velocity non-Darcy effect in the shale matrix, are derived. An accurate solution is achieved through the application of Laplace transformation and Green’s functions. We derive the analytical solutions for transient pressure and production in real space by employing the Stehfest numerical inversion method and obtain the bi-logarithmic type curves. Six distinct flow regimes are identified, and the impacts of salt dissolution, the threshold pressure gradient, the cross-flow coefficient, and the storativity ratio are discussed. This analysis holds significant importance for evaluating fluid flow and transport in inter-salt shale oil reservoirs.

Drilling operations in carbonate rock heavy oil blocks (e.g., in the Tahe Oilfield) are challenged by the intrusion of high-viscosity, temperature-sensitive formation heavy oil into the drilling fluid. This phenomenon often results in wellbore blockage, reduced penetration rates, and compromised well control, thereby significantly limiting drilling efficiency and operational safety. To address this issue, this study conducts a comprehensive investigation into the mechanisms governing heavy oil invasion using a combination of laboratory experiments and field data analysis. Findings indicate that the reservoir exhibits strong heterogeneity and that the heavy oil possesses distinctive physical properties. The intrusion process is governed by multiple interrelated factors, including pressure differentials, pore structure, and the rheological behavior of the heavy oil. Experimental results reveal that the invasion of heavy oil occurs in distinct phases, with temperature playing a critical role in altering its viscosity. Specifically, as temperature increases, the apparent viscosity of the drilling fluid decreases; however, elevated pressures induce a nonlinear increase in viscosity. Furthermore, the compatibility between the drilling fluid and the intruding heavy oil declines markedly with increasing oil concentration, substantially raising the risk of wellbore obstruction. Simulation experiments further confirm that at temperatures exceeding 40°C and injection rates of ≥0.4 L/min, the likelihood of wellbore blockage significantly increases due to heavy oil infiltration. Based on these insights, a suite of targeted mitigation strategies is proposed. These include the formulation of specialized chemical additives, such as viscosity reducers, dispersants, and plugging removal agents, the real-time adjustment of drilling fluid density, and the implementation of advanced monitoring and early-warning systems.

To address the dual challenges of severe lost circulation and wellbore instability in fractured formations, an acrylamide-based lost-circulation-control gel (DF-PG) was synthesized via aqueous-solution free radical polymerization using acrylamide (AM) and sodium acrylate (SA) as monomers, N,N′-methylenebisacrylamide (MBA) as a crosslinker, and ammonium persulfate (APS) as an initiator. The optimal formulation was determined as 6.8% AM, 1.7% SA (mass ratio 4:1), 0.09% MBA, and 0.18% APS, reacted at 60 °C for 4 h. The gel achieves a 276% equilibrium swelling ratio in 20,000 mg/L simulated-formation water, with a compressive strength of 1.2 MPa and temperature resistance up to 120 °C. For fractured cores with 0.5–2.0 mm fracture widths, its sealing efficiency exceeds 95% with breakthrough pressure above 1.2 MPa, and the sealing-efficiency-retention rate remains over 85% after 72 h of scouring. DF-PG realizes the integrated functions of lost circulation control and wellbore stabilization through an “infiltration-swelling-filling“ mechanism, providing a novel technical solution for drilling operations in fractured formations.

Aiming at the industrial problems of traditional sulfonated drilling fluids in high-temperature drilling of deep oil and gas reservoirs at 180°C, including high-temperature degradation, poor environmental protection, and severe reservoir damage, this paper adopts a function-oriented research idea to construct a set of non-sulfonated water-based drilling fluid systems with excellent comprehensive performance and temperature resistance up to 180 °C. Strict screening criteria for single agents were established, and six core non-sulfonated treatment agents were selected from 18 candidate agents in four categories: viscosifiers, fluid loss reducers, inhibitors, and high-temperature stabilizers. The compounding synergistic effects of cross-category treatment agents were studied, and four core action mechanisms were revealed. The optimal formula was obtained through optimization. Tests show that after hot rolling at 180 °C for 16 h, the system has an apparent viscosity retention rate of ≥81%, a yield point retention rate of ≥76%, and a high-temperature and high-pressure filtration loss of ≤12.8 mL. It can resist 15% salt, 1.0% calcium, and 15% drill cuttings, and maintains stable performance under composite pollution. At 180 °C, the shale linear expansion rate is only 8.6%, and the cuttings rolling recovery rate reaches 92.4%. The core permeability recovery value is ≥90.2%, the biotoxicity EC₅₀ value is 42,600 mg/L, and the 28-day biodegradation rate is 68.3%. This system can replace traditional sulfonated drilling fluids and provide a green and feasible technical solution for safe and efficient drilling in deep high-temperature formations.