The vast reserves of natural gas hydrates in offshore areas present significant challenges to development. Surface well construction technology is crucial for the extraction of deepwater natural gas hydrates. To ensure the safety of the subsea wellhead during the drilling process for deepwater natural gas hydrates, a novel conductor suction pile device has been designed, comprising a combination of suction piles and surface conductors. And research has been conducted to investigate the lateral stability characteristics of the conductor suction pile. Drawing upon the pile foundation load-bearing theory and the equilibrium of the differential element, a theoretical analysis model and corresponding governing equations of the conductor suction pile system are established. A solution for a multi-point boundary value problem by simplifying the conductor suction pile system into a two-end free beam is proposed. The governing equations are then converted into a first-order differential equation system, and the four-stage Lobatto IIIa collocation method program for the multi-point boundary value problem is developed and resolved using MATLAB 2023a. Furthermore, a case study of a well in the South China Sea elucidates the effects of wellhead load and seabed soil properties on the lateral load-bearing capacity of the conductor suction pile system, verifying the collocation method’s validity against the results from the finite difference method. After conducting a comparative analysis of the lateral load-bearing performance between conductor suction piles and traditional surface conductors, it is observed that conductor suction piles exhibit lower horizontal displacement and bending moments compared to surface conductors. Therefore, conductor suction piles demonstrate a substantial safety margin. The research findings provide a theoretical basis for the lateral stability of conductor suction piles during deepwater natural gas hydrate drilling. This offers a safe and efficient method for surface well construction in the extraction of natural gas hydrates.

During deepwater drilling operations, when influx gas invades the wellbore, gas hydrates may form through the combination of the gas with free water in the drilling fluid under favorable temperature and pressure conditions. This process can alter the physical properties and flow behavior of the wellbore fluid, potentially leading to safety incidents. To prevent natural gas hydrate formation, mitigate wellbore blockages caused by hydrates, and address the associated safety hazards, this study conducted laboratory experiments to investigate hydrate formation and remediation under multiple deepwater drilling conditions. The hydrate formation boundaries for four different drilling fluid systems—seawater-based bentonite mud, seawater polymer mud, Plus/KCl mud, and HEM mud—were determined for varying well depths and pressure–temperature conditions, and corresponding trend lines were fitted. Key results reveal that a higher carbon content promotes hydrate formation, and the phase equilibrium curves also reveal significant differences among the four drilling fluids. The hydrate aggregation states and blockage processes were clarified for three typical drilling scenarios: drilling, well killing, and drilling suspension. Hydrate formation risk is negligible during normal circulation but increases dramatically during well-killing operations, significantly shrinking the safe operational window. A comparative analysis identified that adding 1% P(M-VCL), a kinetic hydrate inhibitor, to the drilling fluid was the most effective solution, demonstrating superior performance in delaying hydrate nucleation and preventing agglomeration. The study established a complete formation–inhibition–remediation approach for hydrate management in deepwater drilling, thereby enhancing operational safety and efficiency.

To improve the bending resistance and support the domestic development of deepwater subsea wellhead equipment, a three-dimensional finite element model (FEM) of the SXW-15 subsea wellhead system was established in ANSYS Workbench considering contact nonlinearity and rigid-locking mechanisms. Based on representative deepwater drilling and completion conditions, the effects of the friction coefficient, locking preload, blowout preventer (BOP)/lower marine riser package (LMRP) top load, casing hanger internal pressure, and tubing load on the ultimate bending capacity of the system were systematically investigated. The results show that the bending capacity increases with increasing friction coefficient and locking preload, whereas it decreases with increasing top load and tubing weight. The internal pressure of the casing hanger exhibits a pronounced nonlinear influence on the bending resistance, and the maximum bending capacity occurs at an internal pressure of approximately 4000 psi. Based on the mechanical analysis, several innovative designs were proposed, including a layered load-bearing structure, a gravity-set metal sealing assembly, a self-supporting rigid-locking mechanism, and an integrated multifunctional tool system, aiming to improve load-transfer efficiency, connection stiffness, and high-pressure sealing stability. Land-based testing and offshore field applications were subsequently conducted to verify the engineering applicability of the system. The subsea wellhead system with innovative designs maintained satisfactory structural integrity and sealing reliability under conditions of 15,000 psi internal pressure and 12.7 million lb axial load. Good agreement was obtained between finite element predictions and field test results. The present study provides theoretical support and guidance for the structural designs and engineering applications of deepwater subsea wellhead systems.