A combination of 1D and 3D forward and inverse solutions is used to quantify the sensitivity and resolution of conventional controlled source electromagnetic (CSEM) data collected using a horizontal electric dipole source to transverse electrical anisotropy located in a deep-water exploration reservoir target. Since strongly anisotropic shale layers have a vertical resistivity that can be comparable to many reservoirs, we examine how CSEM can discriminate confounding shale layers through their characteristically lower horizontal resistivity. Forward modeling demonstrates that the sensitivity to reservoir level anisotropy is very low compared to the sensitivity to isotropic reservoirs, especially when the reservoir is deeper than about 2 km below the seabed. However, for 1D models where the number of inversion parameters can be fixed to be only a few layers, both vertical and horizontal resistivity of the reservoir can be well resolved using a stochastic inversion. We find that the resolution of horizontal resistivity increases as the horizontal resistivity decreases. We show that this effect is explained by the presence of strong horizontal current density in anisotropic layers with low horizontal resistivity. Conversely, when the reservoir has a vertical to horizontal resistivity ratio of about 10 or less, the current density is vertically polarized and hence has little sensitivity to the horizontal resistivity. Resistivity anisotropy estimates from 3D inversion for 3D targets suggest that resolution of reservoir level anisotropy for 3D targets will require good a priori knowledge of the background sediment conductivity and structural boundaries.3

S U M M A R YObserved deformation is sensitive to a changing stress field within the Earth. However, there are several impediments to a direct inversion of geodetic measurements for changes in stress. Estimating six independent components of stress change from a smaller number of displacement or strain components is inherently non-unique. The reliance upon surface measurements leads to a loss of resolution, due to the attenuation of higher spatial frequencies in the displacement field with distance from a source. We adopt a technique suited to the estimation of stress changes due to the injection and/or withdrawal of fluids at depth. In this approach the surface displacement data provides an estimate of the volume change responsible for the deformation, rather than stress changes themselves. The inversion for volume change is constrained by the fluid fluxes into and out of the reservoir. The distribution of volume change is used to calculate the displacements in the region above the reservoir. Estimates of stress change follow from differentiating the displacement field in conjunction with a geomechanical model of the overburden. We apply the technique to Interferometric Synthetic Aperture Radar (InSAR) observations gathered over a petroleum reservoir in the San Joaquin Valley of California. An analysis of the InSAR range changes reveals that the stress field in the overburden varies rapidly both in space and in time. The inferred stress variations are found to be compatible with the documented failure of a well in the field.