Abstract:
In geo-engineering, hydraulic fracturing (HF) is used to improve the oil/gas production and optimize well stimulation in low permeability reservoirs. To design HF treatments, it is necessary to predict the pattern of fracture geometry as a function of treatment parameters. Present day HF simulators used in the industry are based on rather old approaches, relying on questionable assumptions about fracture geometry and disregarding hydro-mechanical coupling when dealing with fluid pressure evolution. As a consequence, most of the commercial codes fail in the reproduction of the complex intricate fracture patterns shown by the field acoustic measurements [1].
In this contribution we present the application of a recently developed model of brittle damage of confined rock masses to simulate HF treatments. The model is based on the explicit micromechanical construction of connected patterns of parallel equi-spaced cracks, by extending to saturated porous media the dry multi-scale brittle damage model firstly introduced in [2]. A relevant feature of the model is that the fracture patterns are not arbitrary, but their inception, orientation and spacing follow from energetic consideration. The capability of the model to predict the mechanical response of brittle rocks and the related porosity and permeability evolution has been presented in [3] and [4].
The model, based on the Terzaghi effective stress concepts, has been implemented into a coupled hydro-mechanical finite element code, where the linear momentum and the fluid mass balance equations are numerically solved via a staggered approach. The coupled code is used to simulate laboratory and field scale fracturing processes induced by an increase in pore pressure, as in hydraulic fracturing jobs for reservoir stimulation. A reference case, based on typical data of a HF process, has been used to ascertain the influence of different operational parameters on the outcomes of the process. In particular, with reference to a simple geometry, a parametric study is performed by varying the number of wellbore perforations, the number of fracking processes, the distance between the different perforation slots, the wellbore deviation from the minimum principal stress direction axis, fluid pressure, fluid density, and proppant size.
The examples show the capability of the model in reproducing three-dimensional multiscale complex fracture patterns and permeability enhancement in the damaged porous medium.
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