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Success in shale-gas resource systems has renewed interest in efforts to attempt to produce oil from organic-rich mudstones or juxtaposed lithofacies as reservoir rocks. The economic value of petroleum liquids is greater than that of natural gas; thus, efforts to move from gas into more liquid-rich and black-oil areas have been another United States exploration and production paradigm shift since about 2008.

Shale-oil resource systems are organic-rich mudstones that have generated oil that is stored in the organic-rich mudstone intervals or migrated into juxtaposed, continuous organic-lean intervals. This definition includes not only the organic-rich mudstone or shale itself, but also those systems with juxtaposed (overlying, underlying, or interbedded) organic-lean rocks, such as carbonates.Systems such as the Bakken and Niobrara formations with juxtaposed organic-lean units to organic-rich source rocks are considered part of the same shale-oil resource system. Thus, these systems may include primary and secondary migrated oil. Oil that has undergone tertiary migration to nonjuxtaposed reservoirs is part of a petroleum system, but not a shale-oil resource system.

A very basic approach for classifying shale-oil resource systems by their dominant organic and lithologic characteristics is (1) organic-rich mudstones with predominantly healed fractures, if any; (2) organic-rich mudstones with open fractures; and (3) hybrid systems with a combination of juxtaposed organic-rich and organic-lean intervals. Some overlap certainly exists among these systems, but this basic classification scheme does provide an indication of the expected range of production success given current knowledge and technologies for inducing these systems to flow petroleum.

Potential producibility of oil is indicated by a simple geochemical ratio that normalizes oil content to total organic carbon (TOC) referred to as the oil saturation index (OSI). The OSI is simply an oil crossover effect described as when petroleum content exceeds more than 100 mg oil/g TOC. Absolute oil yields do not provide an indication of this potential for production as oil content tends to increase as a natural part of thermal maturation. Furthermore, a sorption effect exists whereby oil is retained by organic carbon. It is postulated that as much as 70 to 80 mg oil/g TOC is retained by organic-rich source rocks, thereby limiting producibility in the absence of open fractures or enhanced permeability. At higher maturity, of course, this oil is cracked to gas, explaining the high volume of gas in various shale-gas resource systems. Organic-lean rocks, such as carbonates, sands, or silts, may have much lower oil contents, but only limited retention of oil as these rocks have much lower sorptive capacity. The presence of organic-lean facies or occurrence of an open-fracture network reduce the importance of the sorption effect.

The oil crossover effect is demonstrated by examples from organic-rich but fractured Monterey, Bazhenov, and Bakken shales; organic-rich but ultra-low-permeability mudstone systems, such as the Barnett and Tuscaloosa shales; and hybrid systems, such as the Bakken Formation, Niobrara Shale, and Eagle Ford Shale, as well as Toarcian Shale and carbonates in the Paris Basin.

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