Evaluation of Moderate Collapse Characteristics and Optimization of Drilling Fluid Density for Horizontal Wells in Deepwater Gas Fields

Conventional drilling fluid density design based on the onset of yielding may not adequately balance wellbore stability against the available mud-weight window in deepwater sandstone–mudstone interbeds, where collapse and lost-circulation risks coexist. Using three-pressure profiles, actual mud weights, and operational records from two field wells in a South China Sea deepwater gas field, a Biot poromechanically coupled Mohr–Coulomb finite element model incorporating pore-pressure diffusion and elastoplastic deformation of the rock skeleton was developed. A numerical method was proposed to characterize the potential collapse extent by the full angular width of a continuous equivalent plastic strain (PEEQ) zone intersecting the borehole wall. The plastic responses of 22 mud-weight cases were examined for two horizontal well orientations. The near-wellbore plastic-zone extent and numerical potential collapse width generally decreased with increasing mud weight. At the same mud weight, drilling parallel to the minimum horizontal principal stress produced a smaller plastic-zone angular width than drilling parallel to the maximum horizontal principal stress. For a 30° angular-width limit, the screened mud weights were 1.130 and 1.110 g/cm3 for drilling parallel to the maximum and minimum horizontal principal stresses, respectively; relaxing this limit to 40° yielded screened values of 1.105 and 1.080 g/cm3. The proposed cumulative-plastic-strain-based angular criterion provides a quantitative basis for selecting well orientation and optimizing mud weight while permitting limited plastic deformation under the specified model conditions.