Many -rich (up to 97% by volume) natural gas pools have been found in the continental margin basins of the northern South China Sea. By combining the geochemical data from 53 samples with their geologic backgrounds, this study investigated the origins and accumulation mechanism of , and discussed the role of in driving oil as it charged the reservoirs. The results reveal that the gases in the Yinggehai basin originate mainly from the thermal decomposition of both Miocene calcareous shales and Paleozoic carbonates, and that from mantle degassing is only a minor contributor. The accumulations in the Yinggehai basin are mainly controlled by diapiric faults and episodic thermal fluid movements. The gases in the eastern Qiongdongnan and western Pearl River Mouth basins are mainly related to magmatic or mantle degassing, and the volatiles from magmatic degassing during the igneous intrusion stage are the most likely major source of in these reservoirs, with basement faults providing pathways for upward migration of -rich mantle fluids. Natural displacements of oil by appear to be common in the eastern Qiongdongnan and western Pearl River Mouth basins. The -flooded oil or gas reservoirs have two common features that the present gas pools or oil-bearing structures have residual oils representing prior charge, and are close to the basement faults that provide pathways along which the mantle-derived -rich gas was migrated. The oils from prior hydrocarbon reservoirs have been naturally driven out by to form secondary oil reservoirs in the eastern Qiongdongnan and western Pearl River Mouth basins. Therefore, a full understanding of the origin and distribution of cannot just be used to trace hydrocarbon migration pathways, but also provide useful information for risk assessment prior to drilling.
Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. A number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. Because the reservoir intervals are shallow and very young, they must have filled with gas rapidly. The thick (up to 17 km) Tertiary and Quaternary sedimentary succession is dominated by shales, and is not disrupted by major faulting in the study area, a factor which seems to have had an important effect on both hydrocarbon generation and fluid migration. Organic‐matter maturation in the deepest, most overpressured compartment has been significantly retarded as a result of the combined effects of excess pressure, the presence of large volumes of water, and the retention of generated hydrocarbons. This retardation is indicated by both kerogen‐related parameters (vitrinite reflectance and Rock‐Eval T max ); and also by parameters based on the analysis of soluble organic matter (such as the C 15+ hydrocarbon content, and the concentration of isoprenoid hydrocarbons relative to adjacent normal alkanes). In contrast to this, organic‐matter maturation in shallow, normally‐pressured strata in the diapiric area has been enhanced by hydrothermal fluid flow, which is clearly not topography‐driven in origin. As a result, the hydrocarbon generation “window” in the basin is considerably wider than could be expected from traditional geochemical modelling. These two unusual and contrasting anomalies in organic‐matter maturation, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of the intense overpressuring, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids (both water and hydrocarbons) retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract More than ten gas pools in the shallow water region of the Pearl River Mouth (PRM) Basin and the Qiongdongnan (QDN) Basin, the Offshore South China Sea have been discovered since 1983. Gases produced from QDN Basin are characterized by high contents of benzene and toluene and relatively heavy delta13C2 values (-25- -27 permil), and the associated condensates by high abundance of bicadinanes and oleanane, which indicate a good correlation with the coal-bearing sequence of the Oligocene Yacheng Formation in the Basin. In contrast, the gases from PRM Basin contain lower amounts of benzene and toluene, lighter delta13C2 values(-24- -34 permil), and a widely variable concentration of bicadinane and oleanane was identified from the associated condensates, which can be largely correlated with the Lower Oligocene Enping Formation source rocks formed in swamp to shallow lake in the Basin. The available geochemical data have indicated that both the Yacheng Formation and the Enping Formation from the basins contain mainly type III-II2 kerogen with dominant gas potential. The regional geological background indicates that the deep water regions of the two basins share the same hydrocarbon source sags with the shallow-water areas, and developed massive sandstone reservoirs during Oligocene and Miocene. Fluid flowing modeling results show that the deep water regions were on the pathway of lateral migrating gases, implicating to be favorable habitats for gas accumulation. In addition, the reservoirs in the zones have developed abundant bright spots which may reflect the presence of gas. Therefore, it is believed that there are great gas exploration potentials in the deepwater regions of the Offshore South China Sea, and the combination of geochemical data with basin modeling results will help to better define favourable targeting areas and reduce risk associated with the future deepwater exploration in the basins.
Based on the chemical and stable carbon isotopic composition of natural gas and light hydrocarbons, along with regional geological data, the genetic type, origin and migration of natural gases in the L lithologic gas field, the eastern slope of Yinggehai Sag were investigated. The results show that these gases have a considerable variation in chemical composition, with 33.6%–91.5% hydrocarbon, 0.5%–62.2% CO2, and dryness coefficients ranging from 0.94 to 0.99. The alkane gases are characterized by δ13C1 values of –40.71‰––27.40‰, δ13C2 values of –27.27‰––20.26‰, and the isoparaffin contents accounting for 55%–73% of the total C5–C7 light hydrocarbons. These data indicate that the natural gases belong to the coal-type gas and are mainly derived from the Miocene terrigenous organic-rich source rocks. When the CO2 contents are greater than 10%, the δ13CCO2 values are –9.04‰ to – 0.95‰ and the associated helium has a 3He/4He value of 7.78×10–8, suggesting that the CO2 here is crustal origin and inorganic and mainly sourced from the thermal decomposition of calcareous mudstone and carbonate in deep strata. The gas migrated in three ways, i.e., migration of gas from the Miocene source rock to the reservoirs nearby; vertical migration of highly mature gas from deeper Meishan and Sanya Formations source rock through concealed faults; and lateral migration along permeable sandbodies. The relatively large pressure difference between the "source" and "reservoir" is the key driving force for the vertical and lateral migration of gas. Short-distance migration and effective "source – reservoir" match control the gas distribution.
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