Accurate determination of drilling fluid rheological properties is critical for optimal wellbore maintenance and hydraulic management during drilling operations. However, rheological parameter determination remains challenging due to insufficient experimental data and complex nonlinear relationship between shear stress (τ) and shear rate (γ̇) under elevated pressure-temperature (P-T) environments. This study introduces an innovative methodology for determining rheological parameters, grounded in experimental measurements. First, systematic experiments were conducted on water- and oil-based drilling fluids across temperature (18–200 °C) and pressure (6.89–172.37 MPa) ranges, significantly expanding existing rheological datasets in the literature. Second, a parameter determination method was developed through nonlinear least squares fitting for the Robertson–Stiff (R-S) model, with extensions to other prevalent models including Bingham, Power-law, and Herschel–Bulkley formulations. By leveraging multivariate function extremum conditions within the least squares framework, the parameter identification problem was reduced to solving a system of equations. Validation via comparative analysis demonstrated the method's superior accuracy, computational efficiency, minimal bias, and low variance. Finally, empirical correlations were established to quantify rheological parameter dependencies on temperature and pressure, revealing strong continuity in parameter evolution with P-T variations. Results confirm the experimental fluids' adherence to the R-S model, demonstrating its effectiveness in describing drilling fluid behavior under extreme downhole conditions.

During the deepwater drilling, the complicated gas-liquid-solid multiphase flow will occur if the formation gas enters and migrates in the wellbore. Through understanding of the wellbore flow behaviors is of great importance for the blowout prevention and well control. Considering the dynamic mass and heat transfer process in wellbore caused by alternating ambient temperature field, a multiphase flow model of multicomponent fluid in wellbore is deduced and developed, including the continuity equation, momentum conservation equation and energy conservation equation. Furthermore, the corresponding initial and boundary conditions are proposed for different working conditions in deepwater drilling, and an efficient numerical solution method is established, including dynamic mesh generation method and discrete solution method of partial differential equations. Applied in a deep-water kicking well, the proposed model is used to analyze the multiphase flow rules in the wellbore. The results show that in the process of annular fluid returning from the bottomhole, the pressure generally decreases linearly, while the temperature change is nonlinear. The temperature first rises and then falls at the formation section, and first falls and then rises at the seawater section. Furthermore, the pit gain increases approximately in a quadratic polynomial relationship, caused by the rise and expansion of gas in the wellbore, and the pressure drop and gas influx rate increase at the bottomhole. In the process of kick evolution, the standpipe pressure and bottomhole pressure gradually decrease, which can be an important sign for kick detection.

Horizontal wells, extended-reach wells, and multi-branch wells were often used to exploit subsea oil and gas efficiently. However, during the sand control screen completion of those wells, the sand control screen pipe was easily deformed. Failure occurred when passing through the bending section due to the large bending section in the wellbore trajectory. A parametric analysis model of the screen pipe was established based on ABAQUS and Python software under pure bending load first. Then, deformation patterns and mechanisms were identified and discussed. The effects of parameters on the screen pipe bending deformation patterns and the ultimate moment were analyzed. Finally, an empirical formula for calculating the ultimate moment of the screen pipe was established. The results showed that the deformation of the screen pipe was complex, and three deformation patterns were related to the hole parameters. Due to an increase in the diameter and number of circumferential and axial holes, the ultimate moment of the screen pipe gradually decreased, and the circumferential holes had a more significant effect on the ultimate moment than the axial holes. The established empirical formula could accurately calculate the ultimate moment of the screen pipe, and the average difference between the formula and numerical simulation results was 3.25%.

An improved phase-partitioning model is proposed for the prediction of the mutual solubility in the CO₂-brine system containing Na⁺, K⁺, Ca²⁺, Mg²⁺, Cl^-, and SO₄^2-. The correlations are computationally efficient and reliable, and they are primarily designed for incorporation into a multiphase flow simulator for geology- and energy-related applications including CO₂ sequestration, CO₂-enhanced geothermal systems, and CO₂-enhanced oil recovery. The model relies on the fugacity coefficient in the CO₂-rich phase and the activity coefficient in the aqueous phase to estimate the phase-partitioning properties. In the model, (i) the fugacity coefficients are simulated by a modified Peng-Robinson equation of state which incorporates a new alpha function and binary interaction parameter (BIP) correlation; (ii) the activity coefficient is estimated by a unified equilibrium constant model and a modified Margules expression; and (iii) the simultaneous effects of salting-out on the compositions of the CO₂-rich phase and the aqueous phase are corrected by a Pizter interaction model. Validation of the model calculations against literature experimental data and traditional models indicates that the proposed model is capable of predicting the phase-partitioning behaviors in the CO₂-brine system with a higher accuracy at temperatures of up to 623.15 K and pressures of up to 350 MPa. Using the proposed model, the phase diagram of the CO₂+H₂O system is generated. An abrupt change in phase compositions is revealed during the transfer of the CO₂-rich phase from vapor to liquid or supercritical. Furthermore, the preliminary simulation shows that the salting-out effect can considerably decrease the water content in the CO₂-rich phase, which has not been well experimentally studied so far.

Blowout is one of the most serious safety threats in deepwater drilling. Considering the characteristics of gas invasion in complex formations, gas migration and distribution, and dynamic changes in temperature inside a wellbore, a deepwater well-closing pressure determination method considering thermal-fluid-solid coupling was proposed. The model was verified using actual data, and the average error in the increase in casing pressure during the closing process was found to be 5.42%. The shut-in pressure of oil and gas wells under a transient shut-in process was analyzed. The results showed that the fluid thermal expansion caused by temperature recovery had a significant impact on the change in wellhead backpressure after well closure. Furthermore, the time required for the wellbore pressure to recover to the formation pressure varies nonlinearly with factors such as geothermal gradients, pit gains, bottom-hole pressure, and gas production indices. A pressure calculation chart was developed for deepwater drilling. The shut-in time for deepwater drilling should not be less than 15 min, and in cases where the gas production index is small and the bottomhole pressure difference is large, the shut-in time should exceed 90 min. The results can provide theoretical guidance and technical support for well shut-in processes during deepwater drilling.

In this study, the formation and escape movements of a bubble injected in non-Newtonian drilling fluid through a pore were numerically simulated using a volume of fluid method. The pattern of a single bubble and the pressure and velocity fields of the surrounding liquid phase during the bubble formation were analyzed and compared with experimental results; based on the comparison, the formation and escape properties of the bubble were further studied. In particular, the effects of static shear force, consistency coefficient, and flow behavior index on the growth and escape time of the bubble were analyzed. The results show that, owing to the effect of velocity on the viscosity of a non-Newtonian drilling fluid, the escape time and volume of the bubble increase with an increase in static shear force, consistency coefficient, and flow behavior index. Among the three parameters, the flow behavior index has the greatest effect. This is because the shear disturbance of a bubble to its surrounding fluid during its growth and escape, caused by the shear thinning of a yield-power-law fluid, reduces the fluid viscosity. The shear thinning decreases, and the resistance to the bubble increases as the flow behavior index approaches 1, leading to larger bubble formation times and separation volumes. An empirical formula for predicting the equivalent radius of bubbles considering the liquid yield stress, inertial force, viscous force, and surface tension is established. The average error of predicting the equivalent radius of detached bubble is 0.80%, which can provide a reference for the better study of bubble migration and flow pattern in non-Newtonian fluid.