PETROGRAPHIC STUDY OF ORGANIC MATTER IN THE NEW ALBANY SHALE (DEVONIAN-MISSISSIPPIAN) WITH THERMAL MATURATION: IMPLICATIONS FOR OIL-PRONE KEROGEN TRANSFORMATION AND PRIMARY MIGRATION

Organic matter (OM) in petroleum source rocks is a mixture of organic macerals, which have different evolution pathways with thermal maturation. Understanding the transformation of each maceral to hydrocarbons with maturity is critical for both source rock evaluation and unconventional gas shale reservoir characterization. In this study, organic petrology was used to document the reflectance, occurrence, color and fluorescence of organic macerals in sixteen New Albany Shale samples from early mature (vitrinite reflectance R_o 0.55%) to post mature (R_o 1.42%). The results show that AOM was observed up to the maturity equivalent to R_o 0.79%, but could not be identified at R_o 0.80%. An organic network composed of solid bitumen and AOM was identified from R_o 0.55% to 0.79%, suggesting that solid bitumen network partially replaced original AOM network and a petroleum system was active since the onset of hydrocarbon generation. Alginite represented by Tasmanites cysts start to transform to pre-oil bitumen at the maturity of R_o 0.80%, and shows weak orange yellow fluorescence at this maturity, a change from strong greenish yellow fluorescence of alginite in early mature samples. Alginite could not be identified at the maturity of R_o 0.89%, and bitumen derived from it migrated over a limited distance. In the studied samples, oil-prone kerogens (AOM and alginite) disappeared at the maturity of R_o 0.89% because of their thermal degradation, and solid bitumen became the dominant organic matter, forming the organic network beyond this maturity. A linear relationship between vitrinite and solid bitumen reflectance is derived from the studied samples. The reflectance of vitrinite is higher than that of solid bitumen until R_o 1.00%, after which solid bitumen reflectance becomes higher than vitrinite reflectance. Solid bitumen that fills pore space between mineral grains (e.g. quartz, dolomite, K-feldspar, clays and micas) and cellular pores in inertinite reduces porosity of tight shale reservoirs, but on the other hand, secondary organic nanoporosity in solid bitumen formed by the expulsion of hydrocarbons can provide storage space and migration pathways for oil and gas.