Yangming Zhu

Evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the Puguang gas field, Sichuan Basin, China

The Puguang gas field is the largest gas field found in marine carbonates in China. Marine carbonate reservoirs in this field were buried to a depth of about 7000 m (22,966 ft) and experienced maximum temperature up to 220C before uplift to the present-day depth of 5000–5500 m (16,404–18,045 ft), with present-day thermal maturity between 2.0 and 3.0% equivalent vitrinite reflectance (Ro). Sulfur-rich pyrobitumens with reflectance up to 3.5% are widespread in the reservoirs and resulted from thermal cracking of crude oils most likely generated from Upper Permian source rocks and thermochemical sulfate reduction (TSR). Natural gases in the Puguang gas field have wide variations in nonhydrocarbon gas contents, with H2S contents between 5.1 and 58.3% and CO2 contents between 7.9 and 18.0%. The hydrocarbon gases originated mainly from thermal cracking of accumulated oil but were altered by TSR. Thermochemical sulfate reduction in the study area exerted different effects on the isotope compositions of different hydrocarbon gas components at different TSR stages. The differential increase of 13C values for different gas components reflects transformation from a heavy-hydrocarbon-gas–dominated TSR stage to a methane-dominated TSR stage. This caused a decrease of 13Cmethane13Cethane values and a corresponding conversion from reversed to normal isotope distributions. Thermochemical sulfate reduction in the study area appears to have been limited by sulfate concentrations in the reservoirs. A successive, three-stage TSR series, namely, liquid-hydrocarbon–involved TSR, heavy-hydrocarbon-gas–dominated TSR, and methane-dominated TSR, occurred in reservoirs with sufficient sulfate concentration. Methane can be the dominant organic reactant for TSR, but only at elevated temperature and after most C2+ hydrocarbons are exhausted.

Charging of the Neogene Penglai 19-3 field, Bohai Bay Basin, China: Oil accumulation in a young trap in an active fault zone

The Penglai 19-3 (PL19-3) oil field, the largest offshore oil field in China, was found in shallow reservoirs (700–1700 m, 2297–5577 ft) within the most active fault zone in east China. The PL19-3 anticline was not finally formed until about 2.0 Ma and is cut by densely distributed faults. Source rock and crude oil samples from the PL19-3 field were analyzed to determine the origin and formation mechanisms of this large oil field. Three organic-rich, oil-prone source rock intervals exist in the Bozhong subbasin, each of which has a distinct biomarker assemblage. Oil samples from different wells have different biomarker associations, and three source-related oil classes were identified within the PL19-3 field based on biomarker compositions and multivariate analysis of the data. The PL19-3 field displays considerable compositional heterogeneity. The compositional heterogeneity within the field and comparison between oil samples from the PL19-3 field and those from nearby structures suggest three field-filling directions, which is consistent with the results of migration pathway modeling. The PL19-3 field was charged in the north by oil generated from Dongying Formation source rocks in the eastern Bozhong depression and Bodong depression, in the southeast by oil generated from Shahejie Formation source rocks in the Miaoxi depression, and in the northwest by oil generated from Shahejie Formation source rocks in the central Bozhong depression. Oil charge from multiple source rock intervals and multiple generative kitchens and focusing of oil originating from a large area of the Bozhong depression into the same trap resulted in rapid oil accumulation in the PL19-3 structure and the formation of this large oil field in a very young trap within an active fault zone.

Mechanisms for oil depletion and enrichment on the Shijiutuo uplift, Bohai Bay Basin, China

The Shijiutuo uplift is a major uplift to the north of the Bozhong depression, the largest generative kitchen in the Bozhong subbasin, Bohai Bay Basin. Although the N35-2 trap on this uplift contains a medium-size oil accumulation and the Q32-6 trap contains Chinas third largest offshore oil accumulation, the Q31-1 trap between the N35-2 and Q32-6 traps with very similar evolution history was confirmed to be dry. Biomarker associations of crude oil and source rock samples were analyzed, and three-dimensional migration pathway modeling was conducted to investigate the origin of oils and mechanisms for oil enrichment and depletion on the uplift. Multiple-parameter oil-source correlation and hierarchical cluster analysis using 10 selected biomarker parameters allowed the identification of four source-related oil classes. Almost all oils from the Shijiutuo uplift are derived from the Eocene Shahejie Formation, whereas oils found between the Shijiutuo uplift and the Bozhong depression either are derived from or have important contributions from the Oligocene Dongying Formation. Variations in oil classes and biomarker parameters suggest sequential migration of oil generated from the Shahejie and then Dongying formations in the Bozhong depression, which is reasonably supported by petroleum migration pathway modeling. Oil charge from two oil-prone source rock intervals and, more importantly, focusing of oil originating from a large area of the Bozhong generative kitchen into the same trap accounted for oil enrichment and formation of Chinas third largest offshore oil field in the Q32-6 structure. The complexity and primary control of the sealing surface (top surface of the carrier bed) morphology on the positions of migration pathways caused the Q31-1 trap to be shielded from migration of oil originating from the Bozhong depression, resulting in oil depletion in this trap. Shadows to petroleum migration may occur because of the three-dimensional behavior of petroleum migration, and two-dimensional migration modeling may be misleading in predicting petroleum occurrences.

Thermal evolution and applications of aromatic hydrocarbons in highly mature coal-bearing source rocks of the Upper Triassic Xujiahe Formation in the northern Sichuan Basin

Based on the GC-MS analytical data of aromatic fractions of over forty highly mature coal-bearing source rock samples collected from the Upper Triassic Xujiahe Formation in the northern Sichuan Basin, the thermal evolution of aromatic hydrocarbons during late-mature to over-mature stage (Ro=1.13%–2.85%) was characterized, and aromatic indicators suitable for recognizing the organic source and sedimentary environment of high maturity source rocks were discussed. The results indicated that the concentrations of low carbon-cycle naphthalene as well phenanthrene series reduce gradually with increasing Ro at the highly mature levels. However, some high-cyclic components such as chrysene, benzofluoranthene, and benzo[e]pyrene are relatively enriched, in companying an enhancement of parent aromatic compounds. The variations are attributed to thermal cracking and polymerization reactions due to continuous dehydrogenation under enhanced burial temperature. As thermal maturity rises, MPI1 (Methylphenanthrene Index) values display a two-modal varying trend, namely, increasing when Ro is below 1.80% and decreasing above 1.8% Ro. The relationships between Ro and MPI1 are Ro=0.98MPI1+0.37 for Ro<1.80% and Ro=−0.90MPI1+3.02 at Ro>1.8%, being different from the previous research. The amount of dibenzofurans declines sharply at Ro higher than 1.1%, leading to a significant change of relative composition among dibenzothiophenes, dibenzofurans and fluorenes (referred as three-fluorenes series composition). Thus, this parameter appears to be unsuitable for identifying the sedimentary environment of the highly matured source rocks. 4-/1-MDBT (methyldibenzothiophene) ratio could be served as an effective indicator for organic facies, and can distinguish coals from mudstones at over-maturity in this case. The ratios of 2,6-/2,10-DMP (dimethylphenanthrene) and 1,7-/1,9-DMP and the relative abundance of triaromatic steroids in these highly mature rocks could be considered as biological source parameters for relative input of terrigenous versus aquatic organic matter.