Baojia Huang

Geochemistry, origin, and deep-water exploration potential of natural gases in the Pearl River Mouth and Qiongdongnan basins, South China Sea

More than 10 gas pools have been discovered since 1983 in the shallow-water region of the Pearl River Mouth (PRM) Basin and the Qiongdongnan (QDN) Basin, offshore South China Sea. Gases produced from the QDN basin are characterized by high contents of benzene and toluene and relatively heavy 13C2 values (25 to 27). The associated condensates have a high abundance of bicadinanes and oleanane, providing a good correlation with the coal-bearing sequence of the Oligocene Yacheng Formation in the basin. In contrast, the gases from the PRM basin contain lower amounts of benzene and toluene and lighter 13C2 values (24 to 34). Widely variable concentrations of bicadinane and oleanane were identifiied from the associated condensates, which can be mostly correlated with the lower Oligocene Enping Formation source rocks formed in a swamp to shallow lake environment. Oil-cracked gases sourced from the Eocene oil-prone source rock may also provide some contribution to the PRM basin gases. The available geochemical data indicate that both the Yacheng and Enping formations contain mainly type III and II2 kerogens with dominant gas potential. Regional geological information indicates that the deep-water regions of the two basins share the same hydrocarbon source sags with the shallow-water areas, and they developed massive sandstone reservoirs during the Oligocene and Miocene. Fluid-flow modeling results show that the deep-water regions were on the pathway of lateral migrating gases, and the interpreted reservoirs in these zones have developed abundant seismic bright spots, which may reflect the presence of gas. The deep-water regions of the offshore South China Sea are believed to have great gas exploration potential.

Geochemistry, origin, and accumulation of CO2 in natural gases of the Yinggehai Basin, offshore South China Sea

Geochemical and isotopic data indicate the presence of CO2 of both organic and inorganic origin in the natural gas reservoirs of the Yinggehai Basin. The natural gases with inorganic CO2 commonly show a high content of CO2, ranging from 15 to 85%; a heavier carbon isotope value of CO2, from 0.56 to 8.16; and a lower 3He/4He ratio, ranging from 0.20 to 6.79 107, indicating a crustal origin. These gases occur locally, commonly related to diapir structures. Natural gases rich in hydrocarbons occur widely and are characterized by a low CO2 content, from 0.1 to 5.0%, and a lighter C1 carbon isotope value from 10.59 to 20.7, indicating an organic origin. Geological background and geochemical data indicate that the Sanya and Meishan formations are the main source of hydrocarbon gases and the organic CO2. Pyrolysis experiments on Tertiary calcareous shales and thermal history modeling both suggest that the calcareous shales occurring in the lower Miocene strata are the main source of the inorganic CO2 gas, whereas thermal contact metamorphism of the Paleozoic carbonates and/or magmatic CO2 may have made only a small contribution. Abnormally high paleogeothermal gradients (4.25–4.56C/100 m; 12.09–12.26F/100 ft) and a rapid heating rate caused the lower Miocene calcareous shales to reach the threshold temperature (about 300C [570F]) of their thermal decomposition at the burial depth of about 6500 m (21,300 ft) and to generate great volumes of inorganic CO2 gas. Diapir faults acted as the main pathways for the upward migration of deep inorganic CO2 gases into reservoirs connected with shale diapirism along the central Yinggehai Basin. The heavier carbon isotope values of associated methanes and a strong thermal anomaly in the CO2-rich gas reservoirs provide evidence that the inorganic CO2 gas migrated into the reservoirs later than their associated hydrocarbon-rich gases. This suggests that the earlier formed traps and sandstone reservoirs distant from shale diapir structures may have greater potential in the exploration for hydrocarbon-rich gases.

Origin and accumulation of CO2 and its natural displacement of oils in the continental margin basins, northern South China Sea

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.

Characterization of Eocene lacustrine source rocks and their oils in the Beibuwan Basin, Offshore South China Sea

Two hundred twenty five rock samples and thirty seven oil samples from the Beibuwan Basin, South China Sea, were analyzed with geochemical and organic petrological techniques to evaluate the Eocene lacustrine source rocks, and investigate controls on their properties and the distribution of different oil families in the basin. Two types of organic facies are recognized in the Liushagang (LS) Formation. The first organic facies is algal-dominated, and mainly occurs in the organic-rich, laminated mudstones of the middle member of the LS (LS-2) that were deposited in an anoxic, stratified, medium–deep lake environment. It is geochemically identified by its high abundance of C30 4-methylsteranes and heavy δ13C values in the range of -22.4 to -27.5‰. The organic matter in this organic facies comprises type I and II1 kerogens, with its macerals dominated by fluorescent amorphous organic matter (AOM) and exinites, indicating a highly oil-prone character. The second organic facies is of terrestrial algal origin, and is mainly identified in the non-laminated mudstones of the upper (LS-1) and lower (LS-3) members of the Liushagang Formation that were deposited in shallow, dysoxic, weakly stratified, fresh-water environments. Source rocks of the second organic facies mainly contain type II1–II2 kerogens with mixed macerals of AOM, internites and vitrinites. It is geochemically differentiated from the algal-dominated organic facies by its relatively low abundance of C30 4-methylsteranes and lighter δ13C values in the range of -27.20 to -28.67‰. Three oil groups are identified by their biomarkers and stable carbon isotopes. The first two groups (A and B) are probably end-members of two major oil families (A and B) that correspond to the algal-dominated organic facies and algal-terrestrial organic facies, respectively. Most of the discovered oils belong to Group A oils that are characterized by a high abundance of C30 4-methylsteranes and heavy δ13C values, and show a good correlation with the algal-dominated organic facies in LS-2. Group B oils are found only within the LS-1 and LS-3 reservoirs, and they are recognized by their relatively low content of C30 4-methylsteranes and lighter δ13C values, showing a close relation to the algal-terrestrial source facies within the LS-1 and LS-3members, respectively. Group C oils display intermediate biomarker features and stable carbon isotope values, and are interpreted to be a mixture of Group A and B oils. The oil-source correlation reveals a strong control of organic facies on the geographic distribution of oil groups or oil fields in the basin.