## 2 Geological Characteristics of Reservoirs  
### Reservoir Porosity and Permeability Characteristics  
Porosity and permeability are critical parameters that quantify the ability of fluids to traverse porous rocks under pressure differentials. Permeability serves as a vital metric for assessing fluid flow through porous media and is governed by [PERSON]'s law. The permeability of a rock with respect to any given fluid is referred to as phase permeability or effective permeability [39]. [PERSON]'s law constitutes a fundamental principle that describes fluid movement within porous media, applicable to both single-phase and multi-phase flow scenarios. The absolute permeability of a rock, denoted as K, is determined through linear flow experiments conducted under conditions of 100% saturation; its value signifies the maximum capacity of the rock for facilitating fluid passage under specified conditions. The magnitude of K primarily depends on factors such as pore throat size, shape, and connectivity, which are intricately linked to the overall pore structure. Relative permeability quantifies a rock's ability to permit each phase of a multiphase flow.  
The porosity and permeability characteristics of reservoir rocks form essential foundations and key determinants of oil and gas production efficiency. Porosity aids in evaluating the storage capacity of reservoirs, whereas saturation assesses their hydrocarbon content. Permeability indicates both the challenges associated with oil extraction processes and their effectiveness within reservoirs. Collectively, comprehensive assessments of reservoir rock permeabilities provide crucial insights for evaluating extraction difficulties and efficiencies; these values are influenced by various factors including pore structure variations in rocks, properties inherent to involved fluids, and states pertaining to multiphase coexistence. Consequently, conducting thorough investigations into reservoir rock permeability characteristics holds significant importance for optimizing strategies related to oil and gas production.  
The Da'anzhai oil reservoir in the central area of the Sichuan Basin is a large-scale fractured reservoir with localized oil enrichment, buried at depths ranging from 2000 to 3000 m. The original formation pressure ranges from 16 to 47.5 MPa, and the formation pressure coefficient ranges from 0.8 to 1.7. The geothermal gradient is approximately 2.07 \({}^{\circ}\)C/m, while the crude oil density falls between 0.6 and 0.8 g/cm\({}^{3}\), with viscosity ranging from 0.2 to 4.0 mPa\(\cdot\)s [40]. The total thickness of the reservoir spans from 40 to 110 m; it is primarily composed of biogenic fragmental limestone and mainly distributed in the Daiyi and Daisya sections. Individual layer thickness generally varies between 3 and 20 m, with cumulative thickness reaching up to 40 m. In addition, the formation thickness in Lianggaoshan area typically ranges between 50 and 150 m. The reservoir is primarily developed in the Lianggaoshan section, characterized by light gray fine-grained (feldspar quartz) sandstone lithology. The individual layer thickness generally ranges from 1 to 4 m, with a cumulative thickness of 10 to 20 m. The reservoir exhibits poor properties, with porosity typically below 2%, permeability below 0.1 \(\times\) 10\({}^{-3}\) um\({}^{2}\), and total organic carbon (TOC) content ranging from 1.2% to 1.7%. It possesses complex geological characteristics including very low porosity, extremely low permeability, and high heterogeneity. In comparison with the features of most low-permeability oil reservoirs domestically and internationally, the Da'anzhai oil reservoir in the Sichuan Basin of China falls into the category of a very low-porosity and low-permeability oil reservoir; its properties are relatively poor, posing greater challenges for development.