Summary Fluid-rock interactions in geological reservoirs can influence pore pressure and induce ground deformation at rates from millimeters to centimeters per year. Elastic deformation models often simplify structural heterogeneity that controls pore pressure and strain distributions, leading to inaccurate interpretations of reservoir properties from geodetic data. Here we investigate how depth-varying rock hydromechanical properties affect the magnitude, rate, and spatiotemporal characteristics of poroelastic deformation and pore pressure. Motivated by the Salton Sea geothermal field, we develop finite-element models of multilayered reservoirs to assess their transient and steady-state behavior in single-well fluid-extraction scenarios. These cases include (1) caprock-reservoir systems with varying permeability and caprock thickness, (2) compaction-induced porosity variations following Athy’s law, and (3) depth-dependent Young’s modulus. While uniformly lower porosity or permeability produces higher rates and earlier onset of deformation and pore-pressure changes, a less permeable or thicker caprock reduces vertical surface displacements, with pressure change reversals near the surface. Young’s modulus varying in alternating or linear profiles generally produces larger vertical displacements and non-monotonic displacement rate histories due to cross-layer fluid migration. Regarding spatiotemporal patterns, porosity or permeability decreasing with depth, or a thicker caprock, accelerates radial expansion of the deformation signal. In contrast, only layered mechanical properties can substantially alter the initial crossover distance and peak-value ratio between the vertical and radial surface displacements, indicating distinct impacts on deformation signatures. Our findings highlight the importance of accounting for structural heterogeneity in predicting and inferring the evolution of poroelastic processes in reservoir systems.
Shodunke et al. (2026) studied this question.