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. Fracture Gradient Determination The traditional method to measure the fracture gradient of a subsurface formation is through the use of leak-off tests. A leak-off test is conducted when casing is set immediately above the interval to be measured and approximately three meters (ten feet) of fresh formation is drilled below the casing shoe in the formation to be tested. Pressure is applied to the casing and the freshly drilled open hole to measure the response of the formation. See Figure 1. Initially, the pressure builds in a linear manner. The initial slope of the pressure versus time plot is determined by the pump rate and the compressibility of the system. The majority of the system compressibility is a result of the fluid compression, with the casing and short length of open hole contributing only a minor amount to the overall compressibility. The pressure continues to build until a fracture is induced in the formation wall. Once a fracture is induced the slope of the pressure build up curve decreases in response to the increased volume associated with the fracture. The point where the slope changes is traditionally known as the leak-off point and is often taken to represent minimum horizontal stress. As pressure continues to increase the fracture extends through a ‘disturbed’ near well bore zone where stresses are typically greater than in situ conditions due to stress redistribution around the well bore, osmotic effects, temperature disturbances, clay reactivity with the mud, interfacial tension etc. The pressure will typically reach a peak and then decline rapidly, ultimately settling at a propagation pressure that is somewhat lower than the peak pressure. There are a number of plausible explanations for the processes associated with extending the fracture beyond the peak pressure. A common view is that the drop from peak pressure is associated with extending the fracture beyond the disturbed zone and/or getting sufficient fracture width to transmit pressure easily down the fracture. Once the fracture has been extended beyond this region the pressure needs only exceed the minimum horizontal stress for the fracture to propagate. If the pump rate is low, which is the case for leak-off tests, the excess pressure will be small and the propagation pressure will be close to the minimum in situ stress.