Tracking hydrothermal infiltration within light oil reservoirs using organic geochemical proxies in the Shunbei area of Tarim Basin in China - Jian Gao; Shaojie Li; Huan Li; Zicheng Cao; Huili Li; Feng Geng; Jun Han; Cheng Huang (Scientific Reports)
Abstract Deep oil reservoirs are becoming increasingly significant fields of hydrocarbon exploration in recent decades. Hydrothermal fluid flow is deemed as a potentially crucial factor affecting the occurrence of deep oil reservoirs, such as enhancing porosity/permeability of reservoirs, accelerating oil generation and thermal cracking, and modifying organic properties of crude oils. Understanding the interplay between hydrothermal fluids and crude oils would provide useful constraints for reconstructing hydrocarbon accumulation processes and predicting the distribution patterns of crude oils. Voluminous crude oils have been discovered in the deeply buried Ordovician carbonate reservoirs within the Shunbei area of the northern Tarim Basin. Previous studies revealed that the Early Permian Tarim Large Igneous Province (LIP) has affected the Shunbei area, whereas it is still debated whether the LIP-related hydrothermal infiltration affected hydrocarbons within the Ordovician reservoirs. To resolve this puzzle, this study was designed to unravel the potential thermal impact of hydrothermal infiltration on hydrocarbons according to molecular and stable carbon isotopic compositions of oils and associated natural gases, reflectance analysis of solid bitumen, and fluid inclusion thermometry. The studied crude oils are characterized by uniform organic indicators of paraffin, terpanes, steranes, and light hydrocarbons, implying that crude oils are derived from the same source rock. Genetic binary diagrams, such as dibenzothiophene/phenanthrene (DBT/P) vs. Pr/Ph (pristane/phytane), Pr/n-C17 alkane vs. Ph/n-C18 alkane, C31R/C30hopane vs. C26/C25tricyclic terpane (TT), and C24/C23 TT vs. C22/C21 TT, indicate that marine shales deposited in a reducing-weakly oxidized environment are major source rocks. Natural gases are associated with oil reservoirs and are mainly generated via the decomposition of kerogen and crude oil. Solid bitumen with abnormally high reflectance values (2.17–2.20%) occurred in the studied area, suggesting their formation temperatures were 252–254 °C. The abnormally high temperatures may be caused by hydrothermal infiltration related to the Tarim LIP. Hydrothermal infiltration is supported by the presence of high contents of CO2 (30–48%) with enriched δ13C ratios (between − 2.5‰ and − 2.3‰), enriched n-alkane δ13C ratios, and incongruent temperatures estimated by multiple indicators, such as light hydrocarbon compositions, homogenization temperatures of fluid inclusions, and bitumen reflectance. Outcomes of this study support the interpretation that hydrothermal infiltration indeed occurred and may have facilitated hydrocarbon generation in the Shunbei area, and possibly elsewhere in the cratonic regions of the northern Tarim Basin.