Determining gas expulsion vs retention during hydrocarbon generation in the Eagle Ford Shale using noble gases. (15th November 2018)

• Record Type: Journal Article
• Authors: Byrne, D.J.; Barry, P.H.; Lawson, M.; Ballentine, C.J.
• Is Part Of: Geochimica et cosmochimica acta. Volume 241(2018)
• Page Start: 240
• Page End: 254
• Publication Date: 2018-11-15
• Subjects: Noble gases -- Shale gas -- Petroleum systems -- Isotope tracers; Geochemistry -- Periodicals; Meteorites -- Periodicals; Géochimie -- Périodiques; Météorites -- Périodiques; Geochemie; Astrochemie; Electronic journals; 551.905
• DOI: 10.1016/j.gca.2018.08.042
• Languages: English
• ISSNs: 0016-7037

Abstract

Abstract: The recent proliferation of tight or unconventional petroleum bearing reservoirs as an energy resource enables a more detailed investigation of the geochemical behaviour of these systems. In addition, it provides an opportunity to improve our understanding of low-permeability crustal fluid systems at depth. Organic-rich shales are not only the source-rocks in conventional petroleum systems, but potential seals, which may be important for the trapping and storage of CO2 and/or nuclear waste. The use of noble gas isotopes as tracers of fluid provenance and physical exchange processes is well established in other crustal fluid systems. Noble gas concentrations and isotopic characteristics were determined in 10 natural gas samples produced from the Eagle Ford shale, Texas, along with the concentration and δ 13 C and δD of hydrocarbon gases. By sampling gases produced directly from unconventional reservoirs we are able to determine their residence time and the extent of interaction of these fluids with other fluids in the wider hydrogeological system. The large range in thermal maturity exhibited across the basin, as demonstrated by the range in δ 13 C of methane from −37.8 to −47.5‰ VPDB, allows us to constrain the evolution of the noble gas signature within a source-rock during hydrocarbon generation and expulsion. For the first time, we show that 36 Ar concentrations in hydrocarbon gases are not simply controlled by solubility exchange with formation water. Instead, they are shown to decrease dramatically (from 2.6 × 10 −7 to 7.0 × 10 −9 cm 3 STPcm −3 ) with increasing thermal maturity, which we attribute to a dilution effect as more short-chain hydrocarbon compounds are generated through cracking of kerogen and secondary cracking of oil. We develop a model that combines 36 Ar concentrations with δ 13 C data in order to quantify the retention capacity for generated hydrocarbons, and show that between 40 and 80% of the hydrocarbons generated by the Eagle Ford shale are retained within the formation. We also calculate that radiogenic 4 He concentrations within the Eagle Ford are well in excess of that which could have accumulated internally since deposition and requires contributions from external 4 He sources. The identification of both hydrocarbon expulsion and helium addition to nominally 'tight' formations now provides a process driven and quantitative understanding of the fluid migration dynamics and processes controlling these critical formations.