Numerous time-dependent wellbore instability problems have been reported when drilling through the chemically active Nahr Umr shale formation in the Arabian Gulf. The shale is characterized by the abundance of not only bedding planes at the macro scale but also networks of smaller natural fractures at the micro scale. The presence of fractures weakens the shale mechanically and produces higher permeability fluid flow paths within the low permeability rock formation. Because of different fluid diffusion rates, there are two distinct pore pressure fields in saturated fractured shales. Additionally, in chemically active shale formations, osmotic pressure arises due to the imbalance in mud/shale chemical activity. These facts necessitate a dual-porosity/dual-permeability approach to analytical modeling that incorporates time-dependency, fracture networks, and chemical effects on wellbore stability. However, it is difficult or almost impossible to properly characterize the necessary shale modeling parameters due to the lack of standard-size samples required by conventional testing techniques. In this paper, a comprehensive approach to simulating instability problems for drilling in fractured shale formations from an innovative laboratory characterization technique for “tiny” shale samples to field analytical modeling is presented.
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