A critical stress state around a faulted reservoir prior to production and injection is an important factor in the hydromechanical responses during production. The purpose of this article is to show how the long-range correlations of production rates observed in several oil fields can be reproduced with hydromechanical modeling of a faulted reservoir subjected to a critical stress state prior to production operations. The modeling implies that the permeability distribution in a reservoir that is in a critical stress state is time dependent. A finite-element model with fully coupled geomechanics and flow was used. The modeling has been applied to an approximation of the complex structure of the Gullfaks reservoir in the North Sea, including the far-field stress regimes and fault systems, although the model is considerably simplified in the search for generic, instead of field-specific, principles.
Under a critical stress state, a small change of the effective stress caused by fluid-pressure changes in the reservoir is likely to trigger reservoirwide hydromechanical reactions, irrespective of whether the change was at a local scale or a reservoir scale. Such responses include fault reactivations, volumetric and shear strain changes, induced deformation evolution, and permeability changes. With a permeability enhancement model, permeability increase is expected if fault reactivation and shear strain change occur. In contrast, if the in-situ stress is not at a critical state, the reservoir reacts locally. In this case, the deformation is mainly elastic, and no permeability enhancements occur. Therefore, the impact of inelastic geomechanical interactions (particularly shear deformation) at a critical point is likely to be very influential on reservoir fluid flow. This critical-point behavior gives explanation to the widespread field observations of long-range correlations in well rates, which are inferred to be manifestations of reservoir-scale mechanical responses involving faults, instead of the local hydraulic links that Darcy flow between wells implies. Permeability changes occur during inelastic deformation despite injection pressures being much lower than the confining stress (the minimum total principal stress). The increase in permeability in the reservoir rocks is caused by the dilation normal to the surface of the faults and/or fractures, which is caused by the shearing along the faults and/or fractures, instead of hydrofracturing. This confirms that dilational shearing can develop despite the effective stress regime being compressive. Dilational shearing has a major impact on the deformation of reservoir rock during production and is an important mechanism for generating conductivity on fractures under a fluid pressure that is lower than the confining stress, possibly even in reservoirs under depletion.