Weilin Zhu

Upper Miocene to Quaternary unidirectionally migrating deep-water channels in the Pearl River Mouth Basin, northern South China Sea

A series of short and steep unidirectionally migrating deep-water channels, which are typically without levees and migrate progressively northeastward, are identified in the Baiyun depression, Pearl River Mouth Basin. Using three-dimensional seismic and well data, the current study documents their morphology, internal architecture, and depositional history, and discusses the distribution and depositional controls on the bottom current–reworked sands within these channels. Unidirectionally migrating deep-water channels consist of different channel-complex sets (CCSs) that are, overall, short and steep, and their northeastern walls are, overall, steeper than their southwestern counterparts. Within each CCS, bottom current–reworked sands in the lower part grade upward into muddy slumps and debris-flow deposits and, finally, into shale drapes. Three stages of CCSs development are recognized: (1) the early lowstand incision stage, during which intense gravity and/or turbidity flows versus relatively weak along-slope bottom currents of the North Pacific intermediate water (NPIW-BCs) resulted in basal erosional bounding surfaces and limited bottom current–reworked sands; (2) the late lowstand lateral-migration and active-fill stage, with gradual CCS widening and progressively northeastward migration, characterized by reworking of gravity- and/or turbidity-flow deposits by vigorous NPIW-BCs and the CCSs being mainly filled by bottom current–reworked sands and limited slumps and debris-flow deposits; and (3) the transgression abandonment stage, characterized by the termination of the gravity and/or turbidity flows and the CCSs being widely draped by marine shales. These three stages repeated through time, leading to the generation of unidirectionally migrating deep-water channels. The distribution of the bottom current–reworked sands varies both spatially and temporally. Spatially, these sands mainly accumulate along the axis of the unidirectionally migrating deep-water channels and are preferentially deposited to the side toward which the channels migrated. Temporally, these sands mainly accumulated during the late lowstand lateral-migration and active-fill stage. The bottom current–reworked sands developed under the combined action of gravity and/or turbidity flows and along-slope bottom currents of NPIW-BCs. Other factors, including relative sea level fluctuations, sediment supply, and slope configurations, also affected the formation and distribution of these sands. The proposed distribution pattern of the bottom current–reworked sands has practical implications for predicting reservoir occurrence and distribution in bottom current–related channels.

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.

Factors controlling petroleum accumulation and leakage in overpressured reservoirs

This paper reviews the hydrocarbon-retaining properties of overpressured reservoirs and discusses the mechanisms for petroleum accumulation, preservation and loss in overpressured reservoirs, and the factors controlling hydrocarbon column heights in overpressured traps. Four types of overpressured traps (filled, underfilled, unfilled, and drained) are recognized. The diversities in petroleum-bearing properties reflect the complexities of petroleum accumulation and leakage in overpressured reservoirs. Forced top seal fracturing, frictional failure along preexisting faults, and capillary leakage are the major mechanisms for petroleum loss from overpressured reservoirs. The hydrocarbon retention capacities of overpressured traps are controlled by three groups of factors: (1) factors related to minimum horizontal stress (tectonic extension or compression, stress regimes, and basin scale and localized pressure–stress coupling); (2) factors related to the magnitudes of water-phase pressure relative to seal fracture pressure (the depth to trap crest, vertical and/or lateral overpressure transfer, mechanisms of overpressure generation); and (3) factors related to the geomechanical properties of top seals or sealing faults (the tensile strength and brittleness of the seals, the natures and structures of fault zones). Commercial petroleum accumulations may be preserved in reservoirs with pressure coefficients greater than 2.0 and pore pressure/vertical stress ratios greater than 0.9 (up to 0.97). The widely quoted assumption that the fracture pressure is 80%–90% of the overburden pressure and hydrofracturing occurs when the pore pressure reaches 85% of the overburden pressure significantly underestimates the maximum sustainable overpressures, and thus, potentially the hydrocarbon-retention capacities, especially in deeply buried traps. Lateral and/or vertical water-phase overpressure transfer from deeper successions plays an important role in the formation of unfilled and drained overpressured traps. Traps in hydrocarbon generation-induced overpressured systems have greater exploration potential than traps in disequilibrium compaction-induced overpressured systems with similar overpressure magnitude.

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.