There are obvious differences in the gas dryness coefficients of different oil and gas reservoirs in the Cainan oil-gas field in the eastern part of Junggar Basin, which is uncommon in petroliferous basins. Based on an analysis of the natural gas components, isotopes, light hydrocarbons, biomarkers, and the gas accumulation process, it is proposed that the mixing of gases from multiple sources and the diffusion process during accumulation are the major constraints on dryness coefficients, influencing them as follows: 1) highly mature coal-type gas dominates in Cainan area, mixed with some oil-type gas, some relatively low-maturity coal-type gas and some shallow secondary microbial gases, resulting in the vertical change in the dryness coefficients and the association of drier gas with crude oil. 2) Part of gases undergo long-distance migration, and the diffusion of gas during this process enriches methane along the migration direction, resulting in the horizontal change in the dryness coefficients; 3) the dryness coefficient changes gradually and is controlled by hydrocarbon generation events and structural changes, reflecting the complex source and accumulation process of natural gas. In this study, we determine why the gas dryness coefficient changes so markedly in the Cainan oil field, obtain a relatively clear understanding of how the three source rocks (Carboniferous, Permian, and Jurassic) contribute to the accumulation of oil/gas, and emphasize the application of dryness coefficients in the study of natural gas with complex origins.
The presence of the NW-trending faults in the northwestern Junggar Basin (NW China) and their relation to hydrocarbon migration were discussed. The presence of the faults was confirmed by new seismic and stratigraphic studies. They formed a rectangular-shape fault system together with the previously and commonly acknowledged NE-trending faults. Hydrocarbon shows are present widely in the cross of the two types of faults on the basis of field survey. Representative shows were further analyzed by petrography and geochemistry, in order to understand hydrocarbon migration features. It is implied that the two types of faults are both significant for the migration. In particular, the newly identified NW-trending faults can act as the primary and ultimate pathway for migration from the petroleum source to accumulation areas. Thus a new complex fault-controlled hydrocarbon migration model was suggested. Favorable hydrocarbon exploration targets were predicted according to the model, providing new information for shaping exploration and exploitation strategies. The results also have wide implications for the study in elsewhere mountain-front piedmont areas where the hydrocarbon exploration and exploitation is generally related to fault.
Authigenic clays and calcite cements are important in the development of reservoir tightness and the formation of hydrocarbon sweet spots. We investigated Jurassic low-permeability sandstone reservoirs in the central Junggar Basin, NW China, using petrography, mineralogy, porosity, and permeability assessment, and stable C and O isotope analysis to ascertain the influence of authigenic clays and calcites on reservoir quality. Here, we establish the properties and diagenetic processes of the reservoir sandstones, and construct a generalizable model of reservoir quality. The results show that the sandstones are mainly litharenite and feldspathic litharenite and can be classified into ductile-lithic-rich sandstones and ductile-lithic-poor sandstones according to rock composition. The ductile-lithic-rich sandstones are tight (mean porosity = 7.31%; mean permeability = 0.08 mD) as a result of intense compaction. In contrast, the ductile-lithic-poor sandstones can be classified into five types according to diagenetic process. The formation of favorable hydrocarbon reservoir properties is closely related to the presence of authigenic clays and dissolution of calcite. In particular, kaolinite fills intergranular pores, thereby blocking pore space and reducing reservoir quality. Chlorite coating resists compaction and limits the formation of quartz overgrowths, thereby preserving pore space and enhancing reservoir quality. Calcite controls reservoir quality through both precipitation and dissolution. Calcite precipitation results in reduced reservoir quality, whereby early calcites that were precipitated in formation water resist compaction and provide the basis for subsequent dissolution and late precipitation, whereas dissolution of calcite in mesodiagenesis improves reservoir quality. A generalized model is formulated by relating diagenetic facies types to depth and porosity, providing a reference for other similar reservoirs. Our data suggest that deeply buried tight sandstones can be exploration prospects under favorable conditions involving the presence of authigenic clays and dissolution of calcite, as in the central Junggar Basin of this study.
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