Overpressure Expulsion And Its Influences On Hydrocarbon Accumulation In The Dongfang Area Of Yinggehai Basin, Northwestern South China Sea

The Yinggehai basin is tectonically located in the triangle between the Sunda block, South China block, and South China Sea basin and is an impressive target for petroleum exploration, not only because of its huge reserves (prospective gas reserves is 22,800.47 x 108 m3) but also due to its abnormally high pore pressures and high tempertures. The abnormally high pore pressures and high tempertures challenge to the success rate of drilling, and the investigation of overpressures leakage mechanism, process and its influences on hydrocarbon accumulation is critical for successful petroleum exploration.The assessments of the pore pressure/stress coupling and the critical state of natural hydrofracturing were performed, using the in-situ measurements of stress and pressure that operated in vertical boreholes. The identification of vertical venting structures and the revelation of overpressures leakage process were conducted, using the 3D seismic volume calibrated with boreholes. The influences of overpressures leakage on hydrocarbon accumulation were investigated, using the gas geochemical and mineralogical comparisons between two gas fields that have different state of pressure and stress. Based on the qualitative and quantitative studies, the following conclusions can be drawn.1. The vertical principal stress is stronger than the least principal stress at equivalent depth, but is less than the WNW-ESE oriented maximum horizontal stress at equivalent depth. The approximately W-E oriented horizontal compression was established at the Miocene and was primarily generated by the ESE absolute horizontal motion of the Sunda and South China blocks. Fluid pressure gradients of the Miocene mostly greater than 17 MPa/km, and some of them even reach or slightly exceed the least principal stress that is critical for hydrofracturing. The pore pressure/stress coupling ratio of Dongfang area is 0.70, which is similar to the 0.66 for the southwestern South China Sea, but stronger than the 0.58 for the southern South China Sea. Despite the maximum sustainable overpressure of the Dongfang area is less than the southwestern South China Sea where has stronger horizontal compression, it is still greater than the areas of absolutely normal faulting stress regime.2. On the upper slope of western basin margin, the upward terminuses of pipes are adjacent to the base of the Pliocene, while on the crestal positions of the central anticline, gas chimneys’s terminuses are adjacent to the base of the Upper Pliocene interval or above it. This regional difference indicates that the fluid direction shifted from the basin margin to the basin central areas within Miocene interval during the Pliocene uplift. The formation of these vertical venting structures was temporally consistent with the hydrocarbon generation, the overpressure generation, and the uplift of central anticline. Particularly, the trigger mechanism, uplift and stress compression of the Miocene interval, had generated the secondery overpressure in deeply buried, which was then focused flowed to the crests with more than 500 m relief, which was sufficient for the perturbation of pore pressure/stress coupling and the hydrofracturing at shallow burial depth.3. In the Dongfang area, the retention capacities are less than 6 MPa, even reach 0 Mpa for the C1 gas field, while are more than 6 MPa-7MPa for the C2 gas field. The difference of retention capacities indicates the variation of system openness, which contributes to the gas geochemical and mineralogical distinctions between the C1 and the C2 gas fields:The homogeneous deviation of 11 parameters roughly shows "ring" feature, implying a closed hydrocarbon system in the C2 field. Except for the 513n-iC4 distinctly negatively skewed, the other 10 parameters strongly positivly skewed, indicating the low accumulation efficiency (open system) and high maturity of the hydrocarbon system in the C1 field. The expulsion of the early charged low maturity hydrocarbons and organic N2 and CO2 contributed the rich of lately charged high maturity hydrocarbons and inorganic CO2 in the C1 field, while the lately charged high maturity hydrocarbons and inorganic CO2 were diluted by the large amounts of early charged low maturity hydrocarbons and organic N2 and CO2 in the C2 field.Sandstones of the two field have the same sedimentological process, while they are relatively lacking in K-feldspar and chlorite, and rich in illite-smectite mixed layer in the sandstones of C1 field. The sandstones are characterized by ankerite and kaolinite cements in the sandstones of C1 field, but primary calcite and illite cements in the sandstones of C2 field. The strong dissolution of chlorite was suggested to release Mg2+ and Fe2+ to stabilize insoluble Fe-Mg carbonate cements in the sandstones of C1 field. The high abundances of illite-smectite mixed layer and kaolinite, and rare in quartz overgrowths, imply that the potassium and silicon derived from the strong dissolution of K-feldspar and chlorite have been exported from the sandstones of C1 fields. Within 110℃～170 ℃ of homogenization temperature, the salinity of fluid inclusions is lower in the sandstones of C1 fields than that in the sandtones of C2 fields, indicating the leakage of solute in the sandstones of Cl fields.Although porosity was increased by brine leakage in the C1 field (higher openness), the enhancement of porosity that compared with the C-2 field (less openness) is minor, approximately ranges from 1 vol to 4 vol%. More seriously, the improvement porosity was temporally during or after the hydrocarbon charging, thus the risk of hydrocarbons expulsion that accompanied with brines leakage cannot be ignored.