Everyone has a reservoir model; but the models are not very reliable at predicting the details of production. The main reason for this unreliability is the inability of the models to accurately simulate variable fracture geometries along the wellbore(s). One approach is to assume that all fractures along a wellbore are planar and simple, with the same height, length, and permeability. While this might provide reasonable estimates of production and EUR, it fails to accurately describe the drainage volume – inherent in the assumption of uniform fracture geometry for every stage. Another approach is to use a stochastic DFN model along with geomechanical modeling of rock failure to describe the resultant failed fracture geometry. This is used with Monte Carlo techniques that generate hundreds of models to quantify the range of production and the associated uncertainty. While this approach appears more rigorous, it requires quantifying values for a large number of model parameters, most of which have to be estimated, since actual measurements of these parameters are very rare for unconventional wells.

When a reservoir is hydraulically fractured, the basic goal is to enhance the permeability of the reservoir by inducing new fractures and activating the existing natural fractures. The most reliable predictor of a fractured reservoir's production is the level of permeability enhancement achieved by creating a network of failed natural fractures and induced fractures through hydraulic stimulation. A new methodology has been developed that involves quantifying the fracture intensity through a deterministic discrete fracture network (DFN) model explicitly using the measured microseismic data, pumping parameters and rock properties. The fracture intensity can be translated into a permeability tensor using fluid flow principles in fractured media. By accurately understanding, describing and quantifying the permeability enhancement we obtain an improved description of the reservoir model honoring the observed spatial changes in fracture intensity, fracture geometry and drainage volume.

This approach fundamentally changes how we quantify the permeability in our reservoir models. This methodology incorporates actual changes in the fracture intensity along the wellbore, rather than using a theoretical fracture model. This simplifies the reservoir simulation, providing very fast and sufficiently accurate results to understand the production and depletion around single or multiple horizontal wells. One case study from Eagle Ford will be presented.

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