Geochemical Assessment of Unconventional Shale Gas Resource Systems

Abstract

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 blackoil 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 1-Part 2 Jarvie, D. M., 2012, Shale resource systems for oil and gas: Part 2 -Shale-oil resource systems, in J. A. Breyer, ed., Shale reservoirs -Giant resources for the 21st century: AAPG Memoir 97, p. 89 -119.

Evaluation of the hydrocarbon generation potential of the Pimenteiras Formation, Parnaiba Basin (Brazil) based on total organic carbon content and Rock-Eval pyrolysis data

“…In these samples, the value exceeding 100 mg oil/g TOC and other samples indicate that the S 1 is lower than TOC content (Figure 12). However, this does not mean that the other samples did not have oil production, because the handling, preparation, and drying samples can contribute to loss of S 1, as was reported by Jarvie (2012). An oil crossover value less than 100 mg HC/g TOC does not rule out the possibility of having producible oil; it does represent substantially higher risk-based strictly on geochemical results (Jarvie, 2012).…”

“…An oil crossover value less than 100 mg HC/g TOC does not rule out the possibility of having producible oil; it does represent substantially higher risk-based strictly on geochemical results (Jarvie, 2012). For Jarvie (2012), Rock-Eval S 1 is not a live oil quantitation, but instead a variably preserved rock-oil system, and there is certainly the loss of light oil due to evaporation, sample handling, and preparation before analysis.…”

Thermally enhanced shale gas recovery: microstructure characteristics of combusted shale

“…The high content of organic matter provides a large amount of potential adsorption sites for shale gas (Chen et al 2018a). According to the kerogen-type descriptions, the kerogen type of these shale samples is dominated by Type II with the H/C atomic ratios about 1.07 and O/C atomic ratios about 0.145 (Jarvie 2015). The vitrinite reflectance (R o ) is 2.7%, which shows a relatively high thermal maturity, indicating that the shale was in the dry gas window (Jarvie 2015), while for high mature shale (R o = 2.7%) the amount of the dissolved gas would be ignored (Guo 2013).…”

Comparison of biomarkers in retained oil and expelled oil of lacustrine marlstone determined by hydrous pyrolysis: Application to hydrocarbon migration determination in the tight oil reservoir

“…However, a series of physical and chemical changes must occur in the process of thermal evolution and migration, which has been fully studied in oil source correlation and secondary migration (Behar, Lorant, & Mazeas, 2008;Pepper & Dodd, 1995). Compared with conventional oil accumulations in which oil usually migrates over a certain distance from the source rock to the reservoir, oil in tight reservoir usually are very close to source rock with less or even without migration (Jarvie, 2012;Mario, Ronald, & Milton, 1997;Jarvie, 2015). There are some reports about differences between tight oil and source rock.…”