Fracture Gradients in Depleted Reservoirs - Drilling Wells in Late Reservoir Life

Abstract

Abstract A key requirement to successful drilling is the selection of a mud weight that provides sufficient pressure to prevent the influx of formation pore fluids, while at the same time not exceeding the fracturing resistance of formations exposed in open hole. The correct prediction of how pore pressure and fracture resistance varies through the intervals to be drilled is critical to designing an appropriate casing program. In many instances fracture gradient profiles will be well defined from experiences of drilling offset wells. However, in cases where casing programs are modified or sub-subsurface conditions have altered, for example as a result of pressure depletion, predictive methods are required to extrapolate the previous measurements and inferences of the fracture gradient. Conventional wisdom on fracture gradients suggests that pressure depletion can significantly reduce fracture resistance and seriously increase drilling difficulty. However, an alternative theory on fracture gradients, coupled with growing evidence of its applicability, indicates that sands are not in general the cause of losses associated with induced fractures. Despite sands often being under lower in situ stress than adjacent shale layers, it is in fact the shale that are more likely to host an induced fracture responsible for large-scale mud losses. In general, shale has a higher Poisson's ratio than sands. In addition, the extent of pressure depletion will be less in intra-reservoir shale than in the sand layers. Therefore, the predicted effect of reservoir depletion on the fracture gradient is much less if based on the shale intervals than if based on the sands. Here the theories on fracture gradients and the reasons for their differences are discussed. Field examples supporting the more optimistic approach are presented.