(256a) Reservoir Quality Indicators and Relative Thermal Maturity Classification Using Image-Based and Bulk Rock Characterization

Mature source rocks consist of a complex pore space where nanoscale pores are hosted by a heterogeneous matrix with varying minerals and organic components to generate a natural nanocomposite with chemical and textural heterogeneity. Organic and inorganic nanopores in these rocks both store and transport hydrocarbons. The organic-hosted pores are generated during thermal maturation of the rock as hydrocarbons are generated. This paper presents a method using image-based characterization to provide relative comparisons of reservoir quality between wells and a method to combine image-based and crushed rock analyses to compare source rock maturity. The results and workflow presented impact special core analysis for unconventional reservoirs and reservoir quality assessment and can complement characterization obtained by other methods. Scanning Electron Microscopy (SEM) is used for source rock characterization to understand rock texture and compositional variations, porosity, and pore sizes. However, despite having significant benefits to characterization, obtaining quantitative results by SEM is time consuming and costly, and therefore the number of images collected per well is generally limited. Recent advances in image processing make obtaining quantitative data from images more accessible. This improves our ability to gather more image-based data on multiple wells for integration with larger scale measurements. Carbonate rich source rocks were sampled from several wells for SEM imaging. Prior to imaging, the samples were mounted, polished, and ion milled. Large field-of-view SEM images were collected and segmented using supervised machine learning to label the pores, fractures/cracks, organics, high density minerals, and matrix minerals. Finally, post-processing methods were used to correct mislabeled components. The relative amount of organic-contained porosity to total porosity (R1) and the relative amount of organic content to total porosity (R2) were calculated for each sample. Porosity was also obtained using the Gas Research Institute method. Pyrolysis was used to determine the hydrogen index. In general, samples with organic content of >2 vol% and total porosity >1% are considered to be of higher quality than others. Beyond these typical bounds, the results show that the R1 and R2 ratios from image-based data can be used to define samples that indicate potentially better quality. When compared across several wells of similar maturity, these quality metrics and criteria can be applied to suggest wells of better quality. Finally, by comparing image-based data to that measured at larger scales, thermal maturity indicators can also be provided.