Gui Wang

Shale formations commonly develop bedding structures and micro-fractures and exhibit strong elastic anisotropy; however, existing wellbore breakdown pressure models are mostly based on isotropic assumptions. We hypothesize that the elastic modulus anisotropy ratio vE = Eh/Ev dominates wellbore breakdown pressure, while the Poisson’s ratio anisotropy ratio vν = νh/νv plays a secondary but non-negligible role through lateral-deformation coupling. To test this hypothesis, a three-dimensional wellbore stress model for transversely isotropic (VTI) shale is developed using VTI constitutive equations and the Lekhnitskii complex-variable framework. The model is combined with Biot poroelastic theory and the minimum principal stress tensile-failure criterion, and the breakdown pressure is solved by a numerical iterative method. The effects of vE and vν are then systematically analyzed. The results show that vE is the controlling factor: as vE increases from 0.1 to 3, the breakdown pressure evolves non-monotonically, first increasing and then decreasing, with a peak at vE = Eh/Ev = 0.3. Changing vE to 0.5 or 2 significantly shifts the magnitude and extreme-value region of the breakdown pressure. In contrast, under vE = 1, varying vν from 0.1 to 3 produces a slightly nonlinear monotonic decrease in breakdown pressure, with an absolute reduction of less than 10%, indicating that vν mainly redistributes tangential and axial stresses by modifying lateral deformation compatibility. Coupled vE–vν effects are synergistic or antagonistic: they increase the local gradient and asymmetry of the breakdown-pressure response surface and can cause nonlinear responses or trend reversals under extreme anisotropy. Elastic anisotropy also distorts the breakdown pressure versus deviation angle, creating local minima or abrupt changes and narrowing the safe drilling fluid density window. The research findings provide a theoretical basis for wellbore fracture pressure prediction, which can assist in determining the upper limit of the safe drilling fluid density window and provide some reference for wellbore trajectory optimization in shale formations.

Drilling fluids are critical in oil and gas well drilling, particularly deep shale gas drilling. In recent years, applying nanoparticles as additives in drilling fluids has received widespread attention to address the various challenges associated with deep shale gas drilling. This study focused on the performance of three nanoparticle-enhanced oil-based drilling fluids (OBDFs), carbon nanotubes (CNTs), silicon dioxide (SiO₂), and aluminums oxide (Al₂O₃) in terms of improving thermal capacity and cooling efficiency. The potential of the nanoparticles to improve the thermal management capability of the drilling fluids was evaluated by measuring specific heat capacity and thermal conductivity. The results showed that CNTs exhibited the most significant improvement, with thermal conductivity increasing by 7.97% and specific heat capacity by 19.38%. The rheological properties and high temperature and high pressure (HTHP) filtration performance of the nanoparticle-enhanced OBDFs were evaluated, demonstrating that CNTs and SiO₂ significantly improved the rheological stability of the drilling fluids and reduced the filtration loss under high temperature conditions. When 3% CNTs were added, the HTHP filtration loss was reduced by 42.86%, exhibiting excellent sealing properties. The cooling effect of different nanoparticles was evaluated by calculating their effects on the bottomhole temperature. The results showed that CNTs performed the best in lowering the bottomhole temperature by 4.53 °C, followed by SiO₂ by 1.47 °C and Al₂O₃ by only 0.88 °C. The results showed that CNTs were the most effective in lowering the bottomhole temperature. These results indicated that nanoparticles as additives to drilling fluids could significantly increase the thermal capacity and cooling efficiency of OBDFs, making them effective additives for high-temperature deep shale gas drilling applications.

Drill cuttings are broken bits of solid material removed from a borehole drilled by rotary, percussion, or auger methods and brought to the surface in the drilling mud. When these cuttings enter the annulus, they have an effect on the drilling fluid rheology and density, which is, in general, quite difficult to evaluate. By introducing an empirical correlation for the rheological properties of cuttings-laden drilling fluids, this study proposes a pressure-loss prediction method for an extended-reach well (ERW). After verifying the accuracy of this method, a case study is considered and a sensitivity analysis is conducted assuming a yield-power law fluid. The results show that an increased concentration of cuttings in the annulus contributes to an increased annular pressure loss. Compared to their effect on the drilling fluid density, cuttings have a greater impact on the drilling fluid rheology. A larger rate of penetration contributes to an increased annular pressure loss. For higher drilling fluid flow rates, the annular pressure loss first decreases and then it increases. In addition, the annular pressure loss becomes higher as the cuttings’ particle size decreases and the cuttings’ concentration grows.

Drilling fluid with strong inhibition performance is crucial in drilling water-sensitive shale formations. An organic salt compound and polyamine were tested for their ability to inhibit shale swelling and dispersion, both individually and in combination. The linear shale swelling rate can be suppressed to less than 20% when the inhibitors are combined, and the hot rolling recovery rate of shale cuttings can improve up to 85%. The interlamellar spacing d001, zeta potential, particle size distribution, water activity, and adsorptive capacity of clays were tested to determine the suppression mechanism of the shale inhibitors. These results show that the organic salt YJS-2 functioned remarkably in crystal lattice fixation, electric double-layer compression, adjustment of water activity, and enhancement of polymer adsorption onto the clay particle surface. Polyamine can enter the clay mineral interlayer and compress the electric double-layer to some extent. It can also synergistically function with YJS-2. Therefore, a combination of these two shale inhibitors worked synergistically to provide crystal lattice fixation, electric double-layer compression, water activity adjustment, adsorption on the surface of clay particles, and encapsulation.