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Using Produced Oils to Predict Quality of Shale Oil and Gas Petroleum Systems

Abstract

A model for shale-oil and shale-gas producibility requires: sufficient shale thickness, initially hydrogen-rich organic matter and an adequate level of thermal maturity. The rock matrix must impart brittleness to enhance effectiveness of stimulation treatments. Increased pore pressure will also augment the nano- to micro-Darcy matrix permeability. Thus far, successful shale resource plays are comprised of deepwater marine shale/marl source rocks. While paralic and especially lacustrine source rocks can contain large amounts of organic matter that have been thermally matured, there are significant challenges in making these potential plays productive. This may be due to the more clay-rich lithologies adversly affecting rock mechanics properties. To begin any shale resource play evaluation, detailed information about hydrocarbon generation through time is required. This information has historically been derived using source rock data and accompanying basin analysis. However, another method using information from reservoired oils, depositional settings and thermal histories is equally effective. This study utilized a large database of produced oil biomarker (chemical fossils) and stable carbon isotopes covering North and South America, all of Europe except eastern Europe, North and Sub-Saharan Africa, China and a portion of the Far East. The oils themselves are a direct indicator of an existing petroleum system. The question then becomes one of geological and geochemical quality. Interpretation of oil data provided information concerning source rock age, lithology, depositional setting, and thermal maturity. This information then allowed us to compare, contrast and rank the potential of shale gas and shale oil resource plays in each of the regions. The oil-based method identified basins with deepwater marine shale/marl source rocks (type II kerogen) and measured the level of thermal conversion. The oil geochemistry and ancillary geological data analysis correctly identified known North American basins with shale gas/oil production or potential. This calibration allowed extension of the method outside of North America. Comparisons to North American plays indicated relative resource potentials, and subsequent ranking to the sub-basin scale. As samples of reservoired oils are commonly more available than source rock information from outcrop, cores or cuttings, this approach can provide a deeper geochemical understanding of shale resource systems.