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Computed Tomographic Core Scanning to Generate a Carbonate Diagenesis Log in Upper Cambrian Microbial Buildups (Mason County, TX)


Microbial carbonate build-ups are major oil and gas reservoirs around the world, from the Aptian pre-salt offshore Brazil and Angola to the Tertiary on the Arabian Peninsula. The effects of diagenetic alteration on the microbial build-ups and their contemporaneous inter-reef sediments make these reservoirs very complex. Very few microbialite exposures can be studied in the field that outcrop in 3D. A series of world class outcrops in Mason County Texas (Upper Cambrian) have been recently discovered with well-organized microbial build-ups and inter-reef sediment that are 10-12m-thick and exposed in vertical outcrop and on a pavement. The study aims to contrast and quantify, in a series of drilled cores, the extent of diagenetic alteration throughout the build-ups and inter-reef sediment, to correlate to different scales of Computed Tomographic (CT) scanning, and to derive a Diagenesis Log at 0.5mm resolution. The Diagenesis Log tracks the extent of diagenetic alteration of both minerals and pore space. Dual Energy CT scanning and Spectral Core Gamma are used to derive mineralogy (calcite and dolomite) and porosity logs. A diagenetic history is interpreted from thin sections and correlated to high-resolution (1 micron) CT image volumes. A volumetric quantification of the diagenetic minerals and pore types is calculated at the pore scale for each sub-sample, which is then upscaled to core plugs and to whole cores and used as calibration points to normalize the mineralogy logs to generate the Diagenesis Log. A porosity versus permeability trend is calculated at the pore scale and for each rock type, which can be used to create a permeability log rooted in the genesis of the pore space. During this analysis, dolomite was always linked to diagenesis whereas calcite was depositional or diagenetic in origin. Primary and secondary pore types are common in the samples. Mineralogy logs calculated with Dual Energy and Spectral Core Gamma demonstrate a clear differentiation between calcite and dolomite that is validated by thin section petrography and became the foundation for this work. When applied to an oil and gas reservoir, the method described here can reduce uncertainty for characterizing reservoir potential in exploratory or developmental wells if gamma ray, porosity and density open hole logs are available. In a field planned to have tight well spacing, this approach would lead to a drilling program needing less core to understand reservoir quality.