(677b) Characterization of Microfractures in Organic-RICH Shales and Tight Reservoir Rocks of the Bakken Formation By Integrated Microscopy Techniques

An integrated microscopy approach has been employed to characterize microfracture properties of organic-rich shales and tight reservoir rock samples from the Bakken Formation in the Williston Basin, North Dakota. A combination of microscopic techniques, including field emission scanning electron microscopy (FESEM), optical microscopy thin-section analysis, and ultra violet fluorescence (UVF) microscopy, provides an opportunity to characterize hydraulic fractures in unconventional reservoir samples at the nano- and microscale. A determination of nanoscale properties, such as fracture aperture and fracture-fill minerals, can be extremely useful for optimizing hydraulic fracture operations in tight oil formations. Knowledge of fracture-fill minerals also assists in predicting geochemical interactions with hydraulic fracturing fluids or stimulation fluids that could lead to precipitation and, in turn, affect flow within the microfractures. The FESEM technique provides data on nanoscale fracture properties and chemical composition of fracture-fill minerals, while thin-section and UVF analyses allow property determination at the microscale; data from the two scales are interpreted jointly to better understand the impact on subsurface hydraulic fracturing activities.

Preliminary results obtained in this study indicate that the UVF technique has a lower microfracture detection limit around 1 µm, compared to a detection limit of about 2.5 µm for thin-section analysis. Also, about 40%–50% of the fractures detected by UVF are not detected via thin-section analysis. These detection differences might be attributed to the different light exposure modes: transmitted mode for thin-section analysis and reflected mode for UVF. Based on FESEM analysis, fracture-fill material was found to be precipitated salts, organic matter, and/or clays and pyrite. Detailed FESEM fracture morphology made it possible to distinguish between microfractures created in the subsurface during original coring and those created at the surface due to handling and sample preparation. Natural microfractures can also be determined based on their morphological attributes and fill material. These findings are useful for improving predictive reservoir modeling approaches and for enhanced understanding of optimal hydraulic fracturing and/or stimulation practices.