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There are a mass of transitional types of rock including proportionally-predominated shales, secondary siliciclastic sandstones, and carbonate rocks which are in small proportion (major dolostone and minor limestone) in Lucaogou Formation of the Jimusaer Sag of Junggar Basin. These rocks were deposited in brackish lacustrine environment under alkaline to weak alkaline conditions. The various rock types were all formed in reduction environment, but there is the broadest oxidation–reduction varying condition for the shale, and environmental reductivity where dolostones deposited is stronger than that of sandstones. The organic matter in source rocks comes from either aquatic organism or terrestrial organism. As reservoir, parts of sandstones and dolostones contain more primitive solid organic matters which might act as the hydrocarbon-generating material base. Parent material types of source rocks in different lithologies are mainly mixed type of type II 2 -I and have oil-prone characteristic. In the study area, the Ro value corresponding to oil generation peak for source rock is Ro=0.9%, lower than the classic model oil peak Ro=1.0% and thermal maturity of source rocks in multifarious types fall in the stage of oil generation. Determined by relationships of TOC content vs. Bitumen/TOC and TOC content vs. HCI, the lower TOC limit for active rocks is around 1.0%, hereby, about 90% of the shales, all of the limestone, and a third of the dolostone and sandstone are active source rocks. Therefore, there are preferable oil-generating potential of lithologically different source rocks in Lucaogou Formation of the Jimusaer Sag. The shales are chiefly oil-prone source rock and parts of dolostone, sandstone and limestone also have a contribution to the oil reservoirs. [ABSTRACT FROM AUTHOR]

The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I 1 , I 2 , II, III 1 and III 2 ) have been recognized and oil-source correlations have been established. The subgroup I 1 oils originated mainly from lower Permian Fengcheng (P 1 f) carbonate source rocks, subgroup I 2 from P 1 f mudstone source rock and group II oils from Middle Permian Wuerhe (P 2 w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III 1 received contributions from P 1 f carbonates and P 2 w mudstones and subgroup III 2 is a mixture of oils from P 1 f mudstones and P 2 w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III 1 oils have diverse mixing ratios in different reservoir, subgroup III 2 oils are mainly from P 1 f mudstones and P 2 w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils. [ABSTRACT FROM AUTHOR]

The geochemical compositions of crude oils and Permian source rocks from the Mahu depression of the Junggar Basin were analyzed in this study. Based on tricyclic terpanes and isoprenoid biomarkers, three oil groups (I, II and III) can be identified that correspond to different source rock formations and organic facies. After examination of the influence of source facies and thermal maturity, and selected biomarker ratios based on carbazole isomers such as 1-MC/4-MC, 1,8-DMC/2,7-DMC and [a]/([a] + [c])-BC ratios in different oil groups, allowed us to determine the direction of hydrocarbon migration in different reservoirs. In addition, abundant oil inclusions are present with fluorescence colors ranging from yellow to blue-white. These were analyzed by FTIR to distinguish between different sources for the oils. Fluid inclusion petrography and microthermometry were also used to prove two stages of oil migration and their different sources. Taking into consideration possible migration pathways and likely driving forces, we conclude that abnormally high pressure in the Permian sequence acted as the main driving force for oil migration. The major migration pathways were vertical faults in the fault belts and slope areas, and sand bodies in the deeper areas. Group I 1 oils from P 1 f carbonate source rocks in the fault belts mainly migrated vertically through the faults and accumulated in T 1 b reservoirs in the Late Triassic, and were driven by excess formation pressure and buoyancy. Group I 2 oils in the slope areas first migrated vertically within thrust faults from P 1 f mudstone source rock in the Late Triassic, after which they migrated laterally over short distances to accumulate in T 1 b sand bodies. Group II oils from adjacent P 2 w source rocks in the center of the depression migrated mainly in the Late Jurassic, due to abnormally high pressure, and accumulated in nearby T 1 b traps. Some reservoir rocks in the slope area contain two generations of fluid inclusions, implying oil mixing from early-stage P 1 f oils and late-stage P 2 w oils, resulting in the group III oils. Combining these data from biomarkers, pyrrolic nitrogen compounds and fluid inclusions allowed us to construct models of migration and accumulation for oils in the Mahu depression. [ABSTRACT FROM AUTHOR]