## 5 Discussion
### The Impact of Sedimentation on Reservoir Pore Structure in Two Sedimentary Systems
#### 5.2.1 Impact of Diagenesis on Pore Structure
Under the microscope, the delta front reservoirs show only a minimal development of quartz intragranular dissolution pores (Figure 5q). In Es3 in the Linnan Subsag, the burial depth is significant and the palaeotemperature is high, causing the organic matter to have entered a high-maturity stage, with a gradual decrease in organic acids in the tight sandstone reservoirs [73]. During the period of 28-38 Ma, the formation temperature reached 80-120 \({}^{\circ}\)C. The organic matter in the source rocks produced large amounts of organic acids and CO2 during thermal maturation, making the formation water acidic [34; 74]. Since both the sand groups above and below the turbidite reservoirs are source rocks, the turbidite sandstone reservoirs are \"source rock interbedded reservoirs\". The formation water within turbidite reservoirs exhibits higher acidity than those in delta front sandstones adjacent to a single source rock [75; 76; 77]. Consequently, dissolution in turbidite reservoirs is correspondingly more intense. During this period, both sets of tight reservoirs experienced severe feldspar dissolution, resulting in the precipitation of large amounts of SiO2 and kaolinite. SiO2 also provided materials for the secondary enlargement of quartz. Between 19 and 28 Ma, organic acids in Es3 began to undergo thermal decarboxylation, whereas earlier diagenetic dissolution consumed some of the initial organic acids, resulting in a decreased concentration of organic acids and a shift in formation water toward alkalinity. Thus, the delta front reservoirs became more alkaline than the turbidite reservoirs. In an alkaline environment, clay minerals undergo a mutual transformation, accompanied by the formation of late-stage carbonate cements and the dissolution of quartz and secondary enlargement. Eventually, quartz grain dissolution is observed in the delta front reservoirs under the microscope. From 3-19 Ma, a large amount of organic acids were generated due to the evolution of organic matter and the formation water remained acidic. There was a slight dissolution of carbonate cements and late-stage quartz enlargement. Since 3 Ma, Es\({}_{3}\)[3] had reached peak hydrocarbon generation, with organic acids undergoing thermal decarboxylation and substantial decomposition, leading to a reduction in the acidity of the formation water. In summary, during the sedimentary period, Es\({}_{3}\)[3] experienced the alternating acidity and alkalinity of formation fluids, resulting in alkaline dissolution in the delta front sandstone reservoirs, where both feldspar and quartz grain intragranular dissolution phenomena are visible (Figure 12). In the context of enhanced oil recovery, mineral dissolution increases the reservoir porosity and enlarges pore-throat diameters, thereby strengthening the pore connectivity and, consequently, reducing the spatial heterogeneity of the pore network. Studies have shown that the dissolution effect in turbidite reservoirs in the study area is stronger than that in delta front sandstone reservoirs. The dissolution effect significantly improved turbidite reservoirs, contributing to increased reservoir homogeneity. Under the combined influence of compaction and cementation, the primary residual intergranular pores are often triangular, quadrilateral, or irregular polygons, with uneven distributions and poor connectivity. However, dissolution significantly enhances the pore structure and connectivity of tight reservoirs. Based on the above analysis, turbidite sandstone reservoirs, compared with delta front sandstone reservoirs, experience relatively weaker compaction and cementation but stronger dissolution, ultimately resulting in the lower complexity of the pore structure, better connectivity, and greater homogeneity in turbidite reservoirs (Figure 12).