Drilling of shale has long been a challenge due to the strong sensitivity of shale to drilling fluids. Improper selection of drilling fluid may cause strong shale-fluid interaction and, consequently, wellbore instability. It is critical to design drilling fluids so as to minimize the shale-fluid interaction. Shale can possess different behaviors when in contact with fluid (e.g., fracturing, swelling, and dispersion). The differences in shale-fluid interaction are mainly related to its clay minerals, structure, bedding and thin laminae, and pre-existing fractures. The rate and strength of interaction vary for different shales. While strong fracturing or dispersion could happen in just a few minutes for some shales, other shales exhibit only very weak fracturing after days in contact with the same fluid. Confining pressure can significantly reduce the propagation of fractures, but pre-existing fractures can be enlarged or extended due to fluid invasion. Due to the variations of shale and the resulting differences in shale-fluid interactions, the shale behavior of fluid in one area or formation cannot always be extrapolated to another area or formation. For a specific shale formation, the understanding of diagenesis, bedding and thin laminae, pre-existing fractures, and abundance and distribution of reactive clays such as smectite, helps predict the potential shale instability. For example, if shale with high smectite content has not experienced substantial compaction and thermal alteration, it may show a strong tendency for dispersion. Alternatively, if high-smectite shale has experienced strong compaction and thermal alteration and shows laminated structures, fracturing along bedding planes or laminae could be the dominant deformation mechanism in fluids. Our laboratory tests indicate that even for highly reactive shale, proper inhibition can be achieved if the composition and concentration of chemical additives in drilling fluids are selected appropriately.


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