Formation Pore-Pressure Prediction in Carbonate Rocks of the Luzhou Block, Southern Sichuan Basin, Based on Hydro-Mechanical Coupling

Accurate formation pore-pressure prediction is essential for defining a safe drilling-fluid density window and preventing lost circulation, influx, kicks, and wellbore instability. This requirement is particularly difficult to satisfy in the Luzhou Block of the southern Sichuan Basin, where thick carbonate successions are characterized by strong vertical lithological variation, complex pore systems, and heterogeneous mechanical properties. A subset of 77 drilling complications was identified within carbonate intervals from 13 wells, and the compiled drilling-event dataset contains 193 recorded operational events, demonstrating the need for a pressure-prediction method that is more suitable for carbonate formations. Conventional empirical approaches, represented by the Eaton method, are generally effective in normally compacted clastic rocks but may become unreliable in carbonates because acoustic transit time is controlled not only by effective stress but also by lithology, diagenesis, fractures, vugs, and fluid–rock interactions. In this study, a pore-pressure prediction model is developed within a hydro-mechanical coupling framework. Under the assumptions of a homogeneous porous medium, linear-elastic small deformation, constrained horizontal strain, and undrained loading, Biot poroelasticity is used to quantify stress transfer between the rock skeleton and the pore fluid. A dimensionless hydro-mechanical response term is then introduced into the pressure-prediction equation to represent the fraction of overburden stress supported by the pore fluid. The model is assessed using Well A in the 205-well area and Well B in the 203-well area, with available offset-well pressure observations used as reference constraints. Relative to the Eaton method, the proposed approach produces smoother and geologically more consistent pressure profiles in carbonate intervals and agrees more closely with measured pressure data from offset wells. The reported correlation coefficients increase from −0.21 to 0.34 for Well A and from 0.67 to 0.89 for Well B, while the corresponding normalized standard deviations decrease from 0.3036 to 0.0816 and from 0.3445 to 0.1088, respectively, corresponding to relative reductions in normalized standard deviation of approximately 73.1% and 68.4%. These results indicate that, for the carbonate intervals evaluated in Wells A and B, explicitly accounting for fluid–solid coupling can reduce prediction variability and improve consistency with the available offset-well pressure observations. The results support the local applicability of the proposed approach in the studied 203- and 205-well areas.