Fluid Quantification and Kerogen Assessment in Shales Using 13C and 1H Magnetic Resonance Measurements

Hydrocarbon production from shale formations may be key to future energy supplies. Economic viability, however, depends on identifying formation sectors with good reservoir quality that are rich in hydrocarbons and kerogen. Kerogen class, determined using Van Krevelen diagrams of H/C vs. O/C ratios, indicates hydrocarbon type and quality. Routine core analysis techniques for fluid quantification and kerogen assessment in shales are sample destructive, time consuming, and prone to errors. Magnetic resonance (MR) methods are increasingly utilized for shale characterization. To this point, MR methods for shale characterization have focused on probing hydrogen that resides in various shale components such as brine, oil, and kerogen. The varied origin of 1H (hydrogen nucleus) in shales results in multicomponent MR signals, making it challenging to distinguish between various shale components. Moreover, 1H relaxation times of shales are short-lived, making quantitative measurements challenging. We previously demonstrated that 1H T1-T2* measurements outperform 1H T1-T2 measurements for quantification of shale species. In this work, naturally occurring 13C (carbon-13 nucleus) was employed for the characterization of mature and immature oil-rich shale samples. The 13C measurement in shales is beneficial in two ways. (1) Among shale species, only kerogen and oil yield a 13C MR signal. This reduced the signal complexity and improved quantification. (2) 13C relaxation lifetimes are longer compared to 1H. Longer relaxation times enabled more quantitative T1-T2 measurements. The 13C MR signal, resolved using 2D T1-T2 relaxation correlation, provided quantitative measurements of oil content in shales and kerogen carbon content. Combining quantitative carbon and hydrogen measurements from 13C and 1H MR permitted the determination of the H/C ratio, an indicator of kerogen class and maturity.