--> Genesis of deep hydrocarbon accumulations in Chinese basins

AAPG Geoscience Technology Workshop

Datapages, Inc.Print this page

Genesis of deep hydrocarbon accumulations in Chinese basins


Most recently, a giant gas field was discovered in deep formation of Sinian in the Anyue Zone in the Sichuan Basin, where the highest experienced depth and temperature reached 7500 m and 240 ºC respectively. Meanwhile, almost 800 million tons reserves of condensate has been convinced in the Tarim Basin so far [1], which is the largest condensate in the Lower Paleaozoic Era on the planet, the depth of condensate reservoirs generally exceed 6500m, the temperature is above 160℃. Since these explorations of deep reservoirs have attracted more attention across the global, if the origin and formation mechanism of deep condensates and gases could be demonstrated and reconstructed, which is further useful to expect the exploration potential in the deep high-temperature and high-pressure reservoirs of sophisticated petroliferous basins. Essentially, natural gases discovered in marine formations from the Sichuan Basin are of high mature to over mature with vitrinite reflectance (Ro) of 2.0-3.8%, with extremely high dryness (>0.96) and considerable content of H2S (0-14.9%) and CO2 (0-30.0%). The 13C isotope for methane is highly enriched with δ13C1 values from -37.9‰ to -28.5. It is noticed that most gas samples show a reversal trend of stable carbon isotope series for methane and ethane (i.e., δ13C1>δ13C2). A mixing model in terms of δ13C1 and δ13C2 was established to quantitatively determine the contribution of primary gas and secondary gas for natural gases in marine formation in Sichuan Basin. It can be concluded that natural gases in the Cambrian and Sinian formations in the Anyue Zone are mainly attributed to the contribution of oil cracking gas with its content of 50-100% [2]. Though natural gases in the Cambrian and Sinian formations in the Anyue Zone were derived from similar source rocks, the content of ethane is much lower and the values of δ13C2 are apparently higher for gases in the deeper formation. The value of δD1 is positive with δ13C2 during the generation of oil-type gas, while the deuterium (D) isotope of methane was depleted with the increasing of δ13C2 at higher maturity. One reasonable possibility is that formation water have participated in thermal maturation of organic matters or thermal cracking of oils and contributed hydrogen for the generation of methane. Moreover, the giant gas-condensates have been detected the concentration of adamantanes and biomarkers in the condensates as well as the carbon isotopic composition of corresponding gases in the Tarim Basin. It is revealed that the maturity of condensate gases (VREo>2.2%) is pretty higher than that of relevant condensates (VREo<1.9%). Therefore, it could be implied that the formation of condensates could be attributed to the mixture of lately cracking gases with the early accumulated reservoirs. In order to reconstruct the mixing process in the deeper and more mature reservoirs, an advanced model was established to assess the dominant contributor for the condensate gases of the Tarim Basin. It is released the relative content of oil-cracking gases varies from 42% to 98%, and the mixing extent of kerogen and oil cracking gas with various maturities could also lead to the carbon isotope reversal of methane and ethane and the rollover of δ13C2 in the marine gases. Therefore, the occurrences of deep hydrocarbons in sedimentary basins are essentially dominated by several geochemical and geological processes, which include the thermal maturation of organic matters, oil-cracking; gas-washing and fractionation, TSR, water-organics reactions- and hybrid accumulation.