Natural gas hydrate reservoir has been identified as a new alternative energy resource which has characteristics of weak cementation, low reservoir strength and shallow overburden depth. Thus, the stability of subsea equipment and formation can be affected during the drilling process. To quantitatively assess the vertical displacement of the formation induced by hydrate decomposition and clearly identify the influence laws of various factors on wellhead stability, this study established a fully coupled thermo-hydro-mechanical-chemical (THMC) model by using ABAQUS software. The important factor that affects the wellhead stability is the decomposition range of hydrates. Based on this, the orthogonal experimental design method was utilized to analyze the influence laws of some factors on wellhead stability, including the thickness of hydrate formation, initial hydrate saturation, overburden depth of hydrate sediment, and mudline temperature. The results revealed that the decomposition of hydrate weakens the mechanical properties of the hydrate formation, thus leading to the compression of the hydrate formation, further causing the wellhead subsidence. When the duration of drilling operations was 24 h and no decomposition of natural gas hydrate occurs, the wellhead subsidence is recorded at 0.053 m, this value increases with an increase in drilling fluid temperature. The factors were listed in descending order as following, according to their significance of influences on wellhead stability: the thickness of hydrate formation, initial hydrate saturation, overburden depth of hydrate sediment, and mudline temperature. Among the above factors, statistical significance of the mudline temperature was less than 15% confidence level, suggesting that the effect of mudline temperature on wellhead stability is negligible. These findings not only confirm the influence of hydrate decomposition on wellhead stability, but also suggest important implications for the drilling of hydrate-bearing formation.

In the drilling process in permafrost strata, the mass and heat transfer effects may thaw the strata around the boreholes and decrease the content of pore ice, thus causing the mechanical properties of the strata to deteriorate greatly, thus influencing the stability of the borehole walls. In this work, a multiphysics coupling mathematical model was built for the stability of borehole walls in permafrost strata. Based on this model, the leading factors for the influences of the mass and heat transfer effects of drilling fluids on the stability of borehole walls were analyzed, and the influences of different drilling conditions on the stability of borehole walls were studied. The results demonstrate that the heat conduction of drilling fluids to the strata is the most important factor that influences the stability of borehole walls, and the diffusion of salt components affects the freezing temperature of pore water and the pore ice content in the frozen area. As the duration of the drilling increases, the collapsed zones of the borehole walls develop toward the radial and circumferential directions. Decreasing the temperature of the drilling fluids can improve the temperature distribution in the strata around the boreholes and is beneficial to reducing the degree of collapse. The increment in the concentration of salt components in the drilling fluids can decrease the overall temperature distribution in the strata, while the increase in the ionic concentration substantially decreases the pore ice content in permafrost and increases the borehole expansion rate. Enlarging the fluid column pressure of the drilling fluids does not intensify the mass and heat transfer effect of drilling fluids on the strata, while it greatly affects the stress distribution in the strata, shrinks the borehole collapse range, and improves the stability of the borehole walls.

Permafrost is a temperature-sensitive geological formation characterized by low elasticity and high plasticity. Inappropriate engineering design during borehole drilling in permafrost can result in the collapse of surrounding strata. To evaluate the stability of borehole walls, a finite element model was developed based on the inherent physical properties of permafrost. This model was utilized to investigate the thermal, stress, and plastic yield zone evolution around the borehole during drilling with normal-temperature fluids. The borehole expansion rate was employed as a quantitative measure to assess wall stability. The analysis reveals that the strata adjacent to the borehole, when drilled with normal-temperature fluids, experience thawing and yielding, with secondary stress concentrations in unthawed strata driving the progressive expansion of the plastic zone. The degree of plastic deformation diminishes with increasing distance from the borehole. Consequently, the borehole expansion rate was utilized to evaluate collapse risk under varying conditions, including permafrost thickness, depth, plastic strain thresholds, and drilling fluid densities. The findings suggest that normal-temperature drilling fluids are appropriate for thin permafrost layers, whereas for thicker permafrost, adjustments in drilling fluid density are required to ensure the stability of borehole walls due to the elevated temperatures and geostress at greater depths.

A high-temperature resistant suspension stabilizer, SIAM-1, for high-density cement slurry used in deep/ultra-deep well cementing has been successfully developed. This suspension stabilizer is based on the temperature-resistant monomers 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and N,N-dimethylacrylamide (NNDMA). Meanwhile, two functional monomers, long-hydrophobic-side-chain temperature-sensitive monomers and temperature-resistant monomer-modified nano-SiO₂ monomers, were introduced. To enhance the participation of two functional monomers in the polymerization process, a method combining a small amount of acrylamide (AM) and emulsion polymerization was employed, leading to the successful synthesis of SIAM-1 with a high content of functional monomers. The study also explores the effects of polymerization method and AM on the conformational characteristics of the resulting polymers. The results confirm that the polymer structure aligns with the designed configuration, and SIAM-1 demonstrates excellent high-temperature resistance, with a tolerance of up to 210 °C. The optimal dosage of AM was found to be 4% of the total monomer mass. SIAM-1 exhibits excellent high-temperature rheological properties, maintaining a viscosity as high as 128 mP·s at 210 °C. Moreover, it effectively improves the suspension stability of the cement slurry at 210 °C. The density differences in the conventional-density and high-density cement slurries are 0.006 g∙cm⁻³ and 0.039 g∙cm⁻³, respectively. This research is beneficial for increasing the viscosity of the cement slurry at high temperatures, effectively preventing the settlement of solid-phase particles under high-temperature and high-pressure well conditions. Consequently, it enhances the cementing effect of deep/ultra-deep wells and reduces cementing-related risks.

Currently, most crude oil viscosity correlations rely only on API gravity and temperature, resulting in significant limitations in accurately predicting crude oil viscosity. To address this issue, this paper systematically explores the effect of API gravity, and crude oil components (saturates, aromatics, resins, and asphaltenes content), on viscosity based on 251 crude oil samples through sensitivity analysis. To overcome the shortcoming of traditional models, this paper proposes an innovative generalized viscosity model that combines the Levenberg–Marquardt (LM) and universal global optimization (UGO) methods to fully consider the effects of API gravity and various crude oil components. To verify the effectiveness of the model, this paper divides the 251 crude oil samples into a training set (202 samples) and a test set (49 samples) and compares the prediction results of the new model with the traditional. The results show that the prediction accuracy of the new model on the training set and test set is significantly better than that of the traditional model, with the minimum average absolute relative deviation reaching 10.13% and 12.4%, respectively. This study not only improves the accuracy of crude oil viscosity prediction but also provides early warning of increased pipeline friction caused by abnormal viscosity, avoids suspension accidents, and ensures the safe operation of long-distance pipelines.