ABSTRACT An evaluation of an integrated data set collected over the past 12 years designed to identify the parameters controlling reservoir quality and production properties in organic, siliceous mudrocks reveals the key diagenetic processes affecting the development of brittleness in siliceous mudrocks. This work was motivated by the failure of early efforts to correlate brittleness to x-ray diffraction (XRD) mineralogy. The outcome of this analysis has been the recognition of two, often overlapping, pathways to brittleness that are determined at the time of deposition by the relative proportions of clay, detrital quartz, and biogenic silica present in the original sediment and are later affected by burial history. One pathway begins with a phyllosilicate–mud-dominated sediment, and the other begins with a sediment containing common or abundant biogenic silica (opal-A). Both pathways are characterized by compactional porosity loss and both eventually include the generation of authigenic quartz cement; however, the source of that authigenic quartz is different between the two pathways. The authigenic quartz that characterizes the first pathway is developed from the illitization of smectite and is precipitated as a cement within the argillaceous matrix. This authigenic quartz is detectable along with the detrital quartz by XRD analysis. All other factors being equal, the volume of brittle, authigenic quartz cement derived from the alteration of smectite is proportional to the volume of original clay. As a result, the effectiveness of this cement to increase the brittleness of the rock may be impacted by the presence of the ductile clays. In the alternate pathway, authigenic quartz is derived from the transformation of biogenic opal-A and is independent of the amount of clay. Much of the XRD quartz volume in rocks derived from biogenic–silica-rich sediment that contained little or no detrital quartz will comprise a brittle, authigenic cement.

ABSTRACT Scanning electron microscopy (SEM) has revolutionized our understanding of shale petroleum systems through microstructural characterization of dispersed organic matter (OM). However, as a result of the low atomic weight of carbon, all OM appears black in SEM (BSE [backscattered electron] image) regardless of differences in thermal maturity or OM type (kerogen types or solid bitumen). Traditional petrographic identification of OM uses optical microscopy, where reflectance (%R o ), form, relief, and fluorescence can be used to discern OM types and thermal maturation stage. Unfortunately, most SEM studies of shale OM do not employ correlative optical techniques, leading to misidentifications or to the conclusion that all OM (i.e., kerogen and solid bitumen) is the same. To improve the accuracy of SEM identifications of dispersed OM in shale, correlative light and electron microscopy (CLEM) was used during this study to create optical and SEM images of OM in the same fields of view (500× magnification) under white light, blue light, secondary electron (SE), and BSE conditions. Samples ( n = 8) of varying thermal maturities and typical of the North American shale petroleum systems were used, including the Green River Mahogany Zone, Bakken Formation, Ohio Shale, Eagle Ford Formation, Barnett Formation, Haynesville Formation, and Woodford Shale. The CLEM image sets demonstrate the importance of correlative microscopy by showing how easily OM can be misidentified when viewed by SEM alone. Without CLEM techniques, petrographic data from SEM such as observations of organic nanoporosity may be misinterpreted, resulting in false or ambiguous results and impairing an improved understanding of organic diagenesis and catagenesis.

ABSTRACT A new model is proposed to predict porosity in organic matter for unconventional shale reservoirs. This model is based on scanning electron microscopic (SEM) observations that reveal porosity in organic matter is associated with secondary porosity developed within organic matter cement that fills void space preserved prior to oil generation. The organic matter cement is interpreted as solid bitumen resulting from the thermal alteration of residual oil retained in the source rock following oil expulsion. Pores are interpreted to develop within the solid bitumen as a result of thermal cracking and gas generation at increased levels of thermal maturity, transforming the solid bitumen to pyrobitumen. The pyrobitumen porosity model is an improvement over existing kerogen porosity models that lack petrographic validation. Organic matter porosity is predicted by first estimating the potential volume of organic matter cement by deriving the matrix porosity available at the onset of oil generation from extrapolations of lithologic specific compaction profiles. The fraction of organic matter cement converted to porosity in the gas window is then calculated by applying porosity conversion ratios derived from SEM digital image analysis of analogous shale reservoirs. Further research is required to refine and test the porosity prediction model.