Fluid production from or injection into a subsurface reservoir leads to stress pressure changes inside and outside the reservoir. The overburden often consists of low permeability shale, and the undrained pore pressure response may be estimated from Skempton’s empirical equations. The key parameters are Skempton’s A and B, controlling the impact of shear stress and mean stress, respectively. In this paper we show how these parameters can be deduced from anisotropic poroelasticity theory and how they are influenced by plasticity. Laboratory data verify Skempton’s relationship for shales for various stress paths, and show the predicted dependence of A on the orientation of the stress field with respect to the symmetry axis of the sample. Data also show decrease of A as failure is approached, and links this to measured volumetric strain. Assisted by results of geomechanical modeling,
the Skempton parameters are used to estimate in situ pore pressure changes. Pore pressure increase is likely during injection, but may also occur for certain stress paths during depletion. The results may have impact on infill drilling and on induced seismicity.