## 5 Hydrocarbon Accumulation Rules
### Rifted Basins  
Rifted basins can form a \"single-source structure type\" hydrocarbon accumulation model (Figure 8). In the Late Carboniferous-Triassic Karoo rift sequences, the source rocks of the onshore Tsimiroro heavy oil and Bemoolanga oil sands in the Morondava Basin have \begin{table}
\begin{tabular}{c c c c} \hline \hline
\begin{tabular}{c} **Coriole and Zambezi** \\ \end{tabular} \\ \hline \hline \end{tabular}
\end{table} 
Table 2: Basic hydrocarbon accumulation rules for four types of passive continental margin basins. been confirmed to be lacustrine shale and swamp coal-bearing sequences, with the organic matter mainly of Type II and Type III, TOC value generally of 1-6%, hydrogen index (HI) of 17-750 mg/g, and the reservoir mainly of fluvial and delta clastic sandstone, with porosity generally of 12-30% [20]. The source rocks of the Calub gas field and the Hilala gas field discovered in the Obbia Basin are mainly developed in two sets of rift sequences: 1 Karoo Bokh shale has a high organic matter abundance, with a TOC value ranging from 0.5% to 17% and reaching a maximum of 27%. It is developed from medium to overly mature, with a maximum thickness of 450 m and a Ro of 1-1.3%. The organic matter is Type II, mainly generating gas; 2 Lower Jurassic mudstone: it has a thickness of 50-120 m and organic matter of Type II and Type III. The reservoirs consist of Karoo fluvial-delta sand bodies and Jurassic lagoon carbonate rock, of which the grainstone and dolomite have better physical properties, with porosity between 10 and 26%. The source rocks of these two gas reservoirs mainly migrated vertically through faults and accumulated in the fault block traps of the Jurassic rift series. Since the Cretaceous, the sedimentary filling thickness in depressions has generally been less than 2500 m. Because the geothermal gradient is usually less than 35 \({}^{\circ}\)C/km, the source rocks have not yet entered the main hydrocarbon generation period, and they mainly act as regional cap rock, dominated by shale in the lake transgression period. The Late Cretaceous was the main period of hydrocarbon migration. The only heavy oil and oil sands found in the Morondava Basin are located in the Karoo rift sequences, which belong to structural traps or structural-stratigraphic composite traps that were damaged during the late rising process. The common feature of oil and gas discoveries in the Morondava Basin and the Obbia Basin is that their source rocks and reservoirs belong to the Triassic lacustrine sedimentary sequences, and hydrocarbons are accumulated in faulted blocks or fault-stratigraphic composite traps on the slope belt of the faulted depression through vertical (fault) and horizontal (reservoir) migration paths. In addition to the faulted block gas reservoir formed by self-generation and self-storage during the Karoo period, the Jurassic gas reservoir also has oil and gas generated by the lower Karoo strata that migrate and accumulate vertically along faults, forming faulted block traps [14]. Although the Cretaceous system itself does not have the ability to generate hydrocarbons, it cannot be ruled out that the hydrocarbons generated by the underlying two stages of rift sequences migrate along inherited faults into the Cretaceous gravity flow sand bodies (slip-collapse-debris flow), forming stratigraphic traps. This widely distributed inheriting fault provides the channel for upward migration of oil and gas vertically but destroys the connectivity of oil and gas migration and accumulation horizontally and limits  
Figure 8: Hydrocarbon accumulation model of passive continental margin basins of “rifted type”. Single-source structure type. the trap size. The Dohar and Shillabo gas fields in the Obbia Basin are also faulted block traps that generated hydrocarbons from the Karoo strata and migrated to the Jurassic strata. The main exploration target of this type of basin is the structural play of two stages of rift sequences.