Northern Song Hong Tertiary Sedimentary basin is a classic case study of a pull-apart basin in southeast Asia, whose formation was controlled by the India-Eurasia collision, sinistral and dextral strike-slip motion of the Ailao Shan-Red River Shear Zone and Opening of the East Vietnam Sea during the Cenozoic. Unlike the central and southern parts of the basin, the northern Song Hong Basin experienced a very strong inversion during the Late Miocene. This rapid uplift of the region has led to significantly change in lithofacies and sedimentary environments, which are now still poorly understood. This uncertainty is considered one of the main challingings in prediction of the non-structural traps in the region. The recent results derived from well logging and 2D/3D seismic interpretation allowed us to define the Miocene formation in northern Song Hong basin, which are subdivided into three substrata, namely: the Lower, Middle and Upper stratum, which are characterized by typical characteristics of lithology and depositional environments. The Lower Miocene formation is dominated by deltaic environment at the bottom, transitioning to the overlying shelf environment. Lithology of the section varies from coarse-grained sediment (sandstone) to fine grained material such as shale and mudstone upward; The Middle Miocene stratum demonstrate sandier, coalic materials of the delta plain and delta front environments intercalated with swampy shale. In contrast, the Upper Miocene section is characterized by more fluvial and nearshore elements. It is illustrated by presence of the channel-filled sand bodies and mouth/longshore sand bars. These sand bodies demonstrate good porosity and horizontal permeability, which are considered to be good potential reservoir for both structural and non-structural traps in the Miocene formation.
Understanding the permeability-porosity relationships is the key to improving reservoir prediction and exploitation especially in carbonate reservoirs, which are known for their complex textural and diagenetic variation. Rock type classifications have long been proven to be an effective technique for establishing permeability- porosity relationships, enhance the capability to capture the various reservoir flow behavior and prediction for uncored reservoir zones. This study highlights some of those practical and theoretically-correct methods, such as Hydraulic Flow Unit (HFU); Global hydraulic element (GHE), Winland’s R35 method, Pittman method, Lucia method. They are proposed and tested for identification and characterization of the rock types using a database of 555 core plugs from the Miocene carbonate reservoir in the Nam Con Son basin. It is a large isolated carbonate build-up structure which were deposited within a shallow marine platform interior and are dominated by coral, red algal and foraminiferal packstones, wackestones and grainstones. Hydrocarbons in this reservoir have been found in the upper most part of the late Miocene formation. Conventional core data were first used to define and display the cross plot of permeability and porosity. Different charts and cutoff thresholds were used to classified, defined number of rock type and the linear and non-linear equations were established. The predicted core permeability was calculated using different methods and compared with the actual core permeability for each rock type. The predicted reservoir rock type and permeability predictions of HFU method was recognized to give better matching of measured core permeability with coefficient of more than 89%.
The Cuu Long Basin is one of the Tertiary sedimentary basins situated on the continental shelf of Vietnam, which demonstrates the high potential of oil and gas. Apart from fractured granite reservoirs, the Oligocene - Miocene sand bodies are thought to have significant potential for forming non - structural traps. The results of the study on the composition and physical properties of the sediments derived from wells "X" and "Y", block 09 - 1, Cuu Long Basin show that there is a clear difference between the Late Oligocene and Early Miocene sandstone in the well "X", namely the Miocene sandstone shows larger particle size, higher roundness and sortness (TB: 434.2; Ro: 0.69; So: 2.22) than those of the Late Oligocene sandstone (TB: 104.28; Ro: 0.64; So: 1.46). This difference is likely attributed to the fact that the Miocene sandstone was influenced by the marine environment, which intensified the roundness and sortness. Meanwhile, the well "Y" did not show much difference in the physical parameters of the sediments between the Late Oligocene and Early Miocene age ranges. However, the grain size was slightly increased and the roundness was less during the Early Miocene. It is possible that the “Y” well is located closer to the local source. The variation in the physical parameters of the sediments, proportion of sand grains and clay minerals shows that the quality of late Oligocene reservoir is better than that of Early Miocene reservoir, and the Late Oligocene reservoir quality in the "X" well is better than that in the borehole "Y".
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