Abstract Simulation of coupled dynamic fluid flow and geomechanical loading of fractured systems shows that complex behaviours can result, even for geometrically simple fracture systems and simple loading. Using a bi-directionally coupled simulation tool, HYDRO–DDA, we examine how fluids and discontinuum processes interact in a fractured, porous rock layer that is being flexed. The changes in fracture aperture, and hence the equivalent permeabilities of this system, exhibit marked localization or delocalization responses in spite of the geometrical and mechanical simplicity of this model. Typically the linked flow-deformation behaviour develops markedly non-linear responses. In some cases the permeability varies by more than three orders of magnitude for minor changes in input variables. Upscaling methods that are suitable representations of this permeability variation are developed. These non-linear behaviours develop in a porous material, which would be expected to suppress non-linear effects. If the range of behaviours seen in this geometrically simple coupled system is typical of other, potentially more complex, fully coupled systems, then the results obtained here can be used to explain the spatially and temporally high variability of the permeability characteristics of fractured systems.

Abstract Predicting deformation-driven permeability changes in the subsurface requires knowledge of the character and distribution of dilatant and compactant rock damage. Seismic reflection data can be used to gain insight into aspects of the deformation such as the geometry of seismically resolvable faults and bulk material property distributions. However, interpretations of material properties from seismic data are non-unique. This paper addresses the use of established seismic techniques to identify the signatures of fault-associated open fractures, modified and improved by a new linked geomechanics–seismic approach. The paper also addresses how each of stress state and open fractures affect seismic anisotropy. The geomechanics–seismic approach is demonstrated using a model of a North Sea hydrocarbon field in which a series of potential fracture arrays are assumed and the fracture apertures are modified to reflect the geomechanically generated stress states. Seismic anisotropy predictions based on these modified fracture distributions are then compared with a pre-existing seismic anisotropy interpretation to determine the best match. Using geomechanical simulation to support a seismic anisotropy-based method produces a higher-confidence result and can lead to better prediction of altered permeabilities in faulted regions. Because of the geomechanical focus of this Special Publication, the background for seismic identification of faults and inter-fault damage is also outlined, including a review of current seismic practice.

Abstract Petroleum reservoir models are currently built from two-dimensional (2-D) information. An understanding of both the large-scale and internal three-dimensional (3-D) architecture of turbidite channel deposits is important for both hydrocarbon exploration and production. A ground penetrating radar (GPR) survey was undertaken on a study site exposing Upper Carboniferous Ross Formation deposits in western Ireland. Both channel margins and intrachannel fill were imaged in 3-D. Constant-offset, 2-D reflection sections were calibrated by vertical radar profiles. GPR data were integrated with sedimentary and survey data to produce a 3-D model of the study site.