Observations of cast thin sections and SEM reveal that the intergranular spaces of the E₃S² sandstone reservoir are mostly filled with clay matrix and carbonate cement (Plate I-a), resulting in almost no primary pores. Secondary intergranular pores, formed by the dissolution of carbonate cement between clastic particles, are the dominant pore type, followed by intragranular pores formed by the dissolution of feldspar and lithic fragments. Moldic pores formed by the dissolution of ooids and bioclasts are occasionally observed. Fractures are rarely seen in cast thin sections and core observations; however, CT scanning reveals curved, embayed, and randomly distributed non-directional fractures (Plate I-b). These fractures are not seen penetrating the core, have a limited distribution, and are classified as non-conductive fractures. A small number of circular pores are observed around the fractures, suggesting that the fractures may be of dissolution origin.

Mercury injection data of 53 sandstone samples from the E₃S² Member show the following average parameters: displacement pressure of 0.33 MPa, throat radius of 0.99 μm, saturation median radius of 1.00 μm, average pore-throat radius of 1.55 μm, maximum pore-throat radius of 14.96 μm, pore-throat sorting coefficient of 2.05, maximum mercury saturation of 83.99%, and mercury withdrawal efficiency of 29.44%. Through statistical analysis of the capillary pressure curve patterns and their characteristic parameters, the pore structure is roughly classified into two basic types (Figure 3).

Figure 3.Typical capillary pressure curves of pore throat sandstones of of E₃s² in A oilfield.

Type I: Displacement pressure < 0.2 MPa, maximum mercury saturation > 80%, throat radius distribution > 1.0 μm. Characterized by relatively large throats, good sorting, and coarse skewness (fine throats), this type of reservoir has good physical properties and well-developed intergranular pores.

Type II: Displacement pressure ranging from 0.2 to 0.5 MPa, maximum mercury saturation ranging from 60% to 80%, throat radius ranging from 0.25 to 1.0 μm. Characterized by fine throats, poor sorting, and coarse skewness (extra-fine throats), this type of reservoir has poor physical properties.

Statistical analysis of sample physical properties shows that the porosity ranges from 3.73% to 22.30% (average: 13.67%), and the permeability ranges from 0.0001 to 774.08 × 10⁻³ μm² (average: 34.36 × 10⁻³ μm²), indicating a medium-low porosity and low permeability reservoir. The physical properties gradually deteriorate with increasing depth, and there is a good positive correlation between porosity and permeability (Figure 4). This suggests that the seepage channels of the E₃S² Member in this area are mainly pore-related reservoir spaces, less affected by fractures, and thus the reservoir is a porous reservoir dominated by matrix pores.

Figure 4.Porosity and permeability of reservoirs of E₃s² in A oilfield.

Sedimentation not only controls macro-factors such as reservoir scale and 3D distribution but also determines micro-factors (e.g., sediment particle size, matrix content, and rock composition) through hydrodynamic conditions of different sedimentary facies belts. These factors further affect the development of primary pores and permeability differences in the reservoir. Therefore, sedimentation is the inherent material basis and internal factor controlling reservoir physical properties ([4]; [11]; [3]; [1]).

The E₃S² reservoir in the study area was deposited in a braided river delta front and shore-shallow lake environment, including microfacies such as subaqueous distributary channels, mouth bars, interdistributary bays, shore-shallow lake beach bars, and shore-shallow lake mud (Figure 5). Among these, the subaqueous distributary channel microfacies in the delta front has the best physical properties, serving as a favorable sedimentary site for reservoir development (Table 1).

Table 1. The porosity and permeability of E₃s² microfacies in A oilfield.

Figure 5.Characteristics of sedimentary microfacies of E₃s² in A oilfield.

As shown inFigure 5, the subaqueous distributary channel microfacies is dominated by gray medium-fine-grained lithic arkose; the sand bodies are mostly deposited in positive rhythms, with parallel bedding and cross-bedding developed. Gravel imbricate arrangement is visible at the bottom of positive rhythmic sand bodies, and the logging curve shape is box-like or bell-like, with comprehensive logging interpretation indicating mostly oil layers. Local intervals show composite rhythms of superimposed positive and reverse rhythms, reflecting the sedimentary process of delta channel sand bodies advancing and eroding early mouth bars. The beach bar microfacies is mainly composed of dark gray mudstone intercalated with sandy strips and thin-layer siltstone, with wavy cross-bedding developed; the logging curve shape is often serrated funnel-like or wide symmetric finger-like, with comprehensive logging interpretation indicating mostly oil-water layers or water layers. The interdistributary bay microfacies is dominated by argillaceous deposits, with the worst physical properties, making it difficult to form favorable reservoirs. Comprehensive analysis shows that the subaqueous distributary channel microfacies has better porosity, permeability, and oil-bearing property than other sedimentary microfacies, serving as the most favorable reservoir development zone in the area. Sedimentary microfacies macroscopically control the 3D distribution of primary reservoir physical properties.

Grain size analysis and thin-section observation show that reservoir physical properties tend to improve with increasing clastic particle size and decreasing matrix content (Table 2). Larger clastic particles indicate stronger sedimentary hydrodynamic conditions, which facilitate repeated washing and rounding of coarse clastic particles, resulting in good sorting, high rounding, and low matrix content-providing favorable conditions for the preservation of primary pores or subsequent diagenetic modification ([8]; [14]). Therefore, the clastic particle size and matrix content (controlled by sedimentary hydrodynamic conditions) have a significant impact on the physical properties of the reservoir in the study area.

Table 2. The porosity and permeability of E₃s² lithology in A oilfield.

Diagenesis occurs throughout the process of sediment consolidation into rock, further modifying the inherent reservoir physical properties formed by sedimentation. It is the acquired condition and external factor controlling reservoir physical properties. Vitrinite reflectance (R₀) data show that the E₃s² Member has entered the low-maturity evolution stage, with R₀ concentrated in the range of 0.67% to 0.70%. The spore-pollen color is orange-yellow, with a thermal alteration index (TAI) of 2.5 to 2.6. The maximum pyrolysis temperature (Tmax) is mainly distributed between 423 and 437˚C (average: 432˚C). Authigenic clay minerals are dominated by illite, with an average relative content of montmorillonite in illite-smectite (I/S) mixed layers of 20%, indicating a high degree of I/S evolution (ordered mixed layer zone). According to the diagenetic stage division standard for clastic rocks, the diagenesis of the E₃S² Member is mainly in the middle diagenetic stage A. Combined with microscopic observation and previous research results ([10]), the diagenetic evolution sequence of the reservoir can be summarized as follows (Figure 6): compaction → early calcite precipitation → organic acid production → dissolution → secondary pores, authigenic kaolinite, authigenic quartz → illite precipitation → late ankerite filling and replacement. Based on their impact on reservoir porosity and permeability, diagenetic processes can be divided into destructive diagenesis (compaction, cementation) and constructive diagenesis (dissolution).

Figure 6. Diagenesis evolution sequence of E₃s² reservoirs in A oilfield.

1) Compaction

The sandstone reservoir in the study area has a burial depth of −3150 to −3300 m. Compaction is one of the main processes reducing reservoir porosity. With increasing burial depth, the effective stress of the overlying strata gradually increases, leading to a corresponding decrease in reservoir pore volume. As shown in the relationship diagram between sandstone cement content and negative cement porosity (Figure 7), almost all data points fall in the area dominated by compaction. Microscopic observation also reveals that the intergranular contact of clastic particles is mainly point-line or line contact (Plate I-c), followed by concave-convex-line contact; point contact is rare. Plastic clastic particles undergo plastic deformation (Plate I-d) and distortion, with partial pseudomatrix formation. Therefore, compaction is relatively strong, making it difficult to preserve primary pores.

Figure 7.The relationship between compaction and cementation as factors controlling the porosity evolution of sample analysisde.

2) Cementation

a) Carbonate Cementation: During the deposition of the E₃S² Member, the study area had a shallow sedimentary water body, high salinity, and an alkaline diagenetic environment ([18]), leading to widespread carbonate cementation. The average content of carbonate cement is 8.15%, mainly composed of calcite and dolomite. Syngenetic micritic calcite cementation is strong (Plate I-e), forming micritic rims and pore filling; early diagenetic sparry calcite fills pores, forming a matrix-supported cementation. Affected by both compaction and carbonate cementation, primary pores in the early diagenetic stage are difficult to preserve, which significantly reduces the reservoir space.

b) Siliceous Cementation: Siliceous cementation is mainly manifested as quartz overgrowth and intergranular siliceous cement. Quartz overgrowth in the study area is commonly observed under thin-section microscopy (Plate I-f). SEM data show that intergranular siliceous cement locally develops into regularly shaped quartz crystals; some authigenic quartz microcrystals grow on the surface of quartz particles, continuously occupying part of the reservoir space and deteriorating reservoir physical properties (Plate I-g). Meanwhile, the presence of siliceous cement can also enhance the compaction resistance of the sandstone reservoir to a certain extent, exerting a constructive effect on reservoir physical properties.

c) Clay Mineral Cementation: SEM and XRD data show that clay mineral cementation generally deteriorates reservoir physical properties with increasing clay mineral content (Figure 8). The clay minerals in the E₃S² reservoir are dominated by illite (average relative content: 67%), with kaolinite, chlorite, and I/S mixed layers also present. During diagenesis, clay minerals often transform due to changes in temperature, pressure, or the fluid medium they contact. Smectite is transformed into illite through the process of potassium enrichment, aluminum enrichment, desilication, and dehydration, under the interaction with potassium-rich mineral dissolution and pore water. In an alkaline diagenetic environment with potassium feldspar, kaolinite also transforms into illite (Plate I-h), with the simplified reaction formula as follows:

2Al₂Si₂O₅(OH₄) + 2K⁺ + OH⁻ → 2KAl₃Si₃O₁₀(OH)₂ + 5H₂O

Ultimately, illite coats the particle surface in the form of fragments or scales, or divides intergranular pores in a pore-bridging manner (in the form of filaments (Plate I-i) or flakes), increasing the tortuosity and blocking throats, thereby deteriorating reservoir physical properties (Plate I-j).

Figure 8.The relationship between content of clay minerals and petrophysical properties of E₃s² in A oilfield.

3) Dissolution

In a specific diagenetic environment, any clastic particles, matrix, cement, and replacement minerals in clastic rocks—including the most stable quartz and siliceous cement—can undergo dissolution to varying degrees ([5]). The intensity of dissolution depends on the properties (pH, Eh, temperature, chemical composition, etc.) and quantity of fluids passing through the rock, as well as the stability and permeability of rock components. The rock type in the study area is mainly lithic arkose, with soluble carbonate cement developed in the interstitial materials, providing a favorable material basis for later dissolution. Cast thin-section data show that dissolution mainly occurs in intergranular carbonate cement, followed by the dissolution of feldspar and lithic fragments (Plate I-k, l). The main reason is that the burial depth of the study area is approximately 2400 meters. During the maturation of organic matter in source rocks, organic acids are released, which induce dissolution along the edges of soluble minerals (feldspar and lithic grains), grain fracture cracks, cleavage cracks, and the hydrochloride cements between clastic grains. This dissolution leads to the development of expanded intergranular pores, reduced intergranular pores, intragranular pores, and moldic pores are observed; however, the overall dissolution intensity is weak, with no large-scale pores or super-large dissolved pores formed by dissolution. The absolute content of mixed pores is 3.86%, accounting for an average of 70% of the total pores; the absolute content of secondary pores is 1.55%, accounting for an average of 28% of the total pores. The reservoir pores are dominated by expanded intergranular pores, but their absolute content is low. This indicates that dissolution in the reservoir mainly acts on the cement between clastic particles; however, the limited dissolution intensity, while exerting a constructive effect on reservoir physical properties, cannot completely change the low-permeability characteristics of the reservoir.