Interactions of organic-rich shale with water-based fluids
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The success of horizontal drilling and hydraulic fracturing has enabled the economic production of hydrocarbons from shale formations. However, wellbore instability and proppant embedment remain two major concerns during drilling and completion of wellbores in unconventional shale reservoirs. Both issues are largely controlled by shale-fluid interactions. Understanding the interactions of organic-rich shale with water-based fluids is the first step towards selecting appropriate drilling and fracturing fluids. The main objective of this study is to investigate the interactions of organic-rich shale with various water-based fluids. A series of measurements were performed to determine shale mineralogy, native water activity, fluid content, pore size distribution, Brinell hardness, Young’s modulus, P-wave and S-wave velocities. It was shown that XRD and XRF yield consistent shale mineralogy, allowing us to make rapid determinations of shale mineralogy. Large variations in mineralogy were observed with shale samples from different formations. Even samples from the same well and at adjacent depths exhibited very different mineralogical makeup. The NMR T₁/T₂ ratio and T₂ secular relaxation were used to distinguish pore fluids of different viscosity in pores of various sizes. A good correlation was established between the clay content and the amount of low-viscosity fluid in small pores, indicating that the water-saturated microporosity was in clay minerals. Combined N₂GA and MICP measurements showed that a majority of the shale pores were found to be in the micropore to mesopore size range. Changes in shale mechanical properties were measured before and after shale samples came into contact with water-based fluids. The small degree of swelling and mechanical properties changes suggests that these organic-rich shales were only slightly sensitive to fluid exposure. Anisotropic swelling perpendicular and parallel to bedding planes could be due to the clay fabric anisotropy. The importance of using preserved shale samples was clearly demonstrated. Temperature and fluid pH were found to have significant impact on the reduction in shale mechanical stability after fluid exposure. Changes in both shale hardness and Young’s modulus were observed with fluid exposure. Shales with higher clay content tend to experience greater reduction in modulus and hardness after contact with water-based fluids. A comparison between the measured fracture permeability damage and the calculated fracture permeability damage due to proppant embedment alone reveals that proppant embedment caused by shale softening is only partially responsible for the decrease in fracture permeability. Other mechanisms such as fines mobilization may be the dominant factors controlling fracture conductivity damage. Together these measurements allow us to rapidly screen drilling and fracturing fluids that are compatible with a particular shale by studying changes in shale mechanical properties before and after contact with water-based fluids. Potentially troublesome shales can be identified and possible solutions can also be evaluated using this measurement procedure.