The Ordos Basin, located in northwestern China, forms part of the North China Craton and represents a multi-cycle sedimentary basin spanning from the Paleozoic to the Mesozoic eras ( Gao & Wang, 2017 ; Liu et al., 2024 ; Pan et al., 2024 ). The basin exhibits an approximately square shape, covering about 370,000 km², with well-defined boundaries: it borders the Yinshan Orogenic Belt to the north, the Qilian Orogenic System to the west, the Qinling Orogen to the south, and the Taihang Uplift to the east. Structurally, the basin interior is generally stable, dominated by gently dipping monoclines, with localized development of faults and anticlinal structures. The sedimentary cover is thick, featuring widespread Paleozoic, Jurassic, and Cretaceous deposits, establishing the basin as one of China’s premier hydrocarbon accumulation regions. The Yanan Gas Field lies within the Yishan Slope in the southern basin, where the structural framework is simple, faults are sparse, and depositional continuity is favorable, providing an optimal geological setting for the formation of Upper Paleozoic tight sandstone gas reservoirs.

The Yanchuan East Block exhibits complete stratigraphic development, with exposed strata ranging from the Ordovician to the Cenozoic ( Greentree et al., 2006 ; Kuang et al., 2020 ; Xiong et al., 2024 ; Zhang et al., 2022 ). The Carboniferous–Permian succession attains significant thickness and constitutes the primary target for hydrocarbon exploration and development. Carboniferous deposits are widespread, encompassing the Taiyuan and Benxi Formations, characterized by interbedded sandstones, mudstones, and limestones, with localized coal seams. The Permian includes the Shanxi, Shihezi, and Shiqianfeng Formations, featuring interbedded sandstones, siltstones, and mudstones in diverse depositional environments that reflect distinct marine-terrestrial transitional facies. Within the study area, the Benxi Formation occupies the lower Carboniferous, with thicknesses typically ranging from 40 to 80 m. Its lithofacies are dominated by sandstones, interbedded with minor mudstones and limestones, and it developed within a barrier island-lagoon depositional system. Overall, the stratigraphic succession in the Yanchuan East Block is continuous, with stable sandstone body distributions, offering advantageous conditions for investigating reservoir characteristics.

The Benxi Formation formed during the Late Carboniferous, influenced by transgressive–regressive cycles that engendered a complex and variable depositional environment, primarily featuring a barrier island–lagoon system ( Gao & Wang, 2017 ; Li et al., 2023 ; Meng et al., 2024 ; Xu et al., 2021 ; Zhao et al., 2024 ). Barrier island sand bodies exhibit high depositional energy, dominated by quartz sandstones with moderate to well-sorted grains and high roundness. In contrast, lagoonal settings are characterized by siltstones and mudstones, with localized thin coal seams. Provenance primarily derives from paleo-uplifts in the northern and northeastern basin margins, supplying predominantly quartz and volcanic lithic fragments, which provided the material foundation for reservoir formation. Variations in depositional processes and provenance conditions account for the diversity in lithological composition, grain size characteristics, and pore structures of Benxi Formation sandstones, while establishing the groundwork for subsequent diagenetic processes and reservoir evolution.

Based on the “Classification and Nomenclature of Sedimentary Rocks (GB/T 17412.2-1998)” standard, detrital components in Benxi Formation sandstones are dominated by quartzose grains (including quartz and chert), followed by lithic fragments and trace feldspar ( Mo et al., 2021 ; Wu et al., 2023 ). Quartz content ranges from 2.5% to 100%, averaging 77.5%; lithic content from 0% to 97%, averaging 22.3%; and feldspar from 0% to 1.0%, averaging 0.3%. Lithic fragments are predominantly volcanic, succeeded by metamorphic varieties. Lithic constituents mainly include igneous rock fragments and low- to medium-grade metamorphic fragments such as schists, phyllites, slates, and meta-sandstones ( Figure 2 , Figure 3 ).

Authigenic cements in Benxi Formation sandstones primarily comprise carbonates, clay minerals, and siliceous cements ( Gao et al., 2022 ; Ma et al., 2021 ; Xi et al., 2015a ). Carbonate cements include ferroan calcite, ferroan dolomite, and siderite ( Figure 4 ), with ferroan calcite and ferroan dolomite being relatively abundant. Calcite content ranges from 0% to 35%, averaging 1.69%; dolomite from 0% to 16%, averaging 1.22%. Clay mineral cements are chiefly kaolinite and illite, with minor chlorite ( Figure 5 ). Most kaolinite and chlorite are associated with tuffaceous alteration; kaolinite often exhibits detrital outlines as an alteration product of alkali feldspar and volcanic fragments, while vermiform kaolinite derives from the alteration of feldspar-rich tuff.

The Benxi Formation reservoirs in the Yanchuan East Block primarily exhibit three pore types: residual intergranular pores, secondary dissolution pores, and

intracrystalline pores. Intergranular pores predominate, accompanied by minor secondary dissolution pores, intracrystalline pores, and microfractures. Secondary dissolution pores mainly include feldspar and volcanic lithic dissolution pores ( Chen et al., 2024 ; Li et al., 2025a ; Wang et al., 2023 ).

① Residual Intergranular Pores: Intense mechanical compaction has affected the Benxi Formation reservoir sandstones in the study area, resulting in widespread residual intergranular pores between quartz grains, albeit with relatively low abundance. These pores are commonly partially filled by clay minerals such as illite and kaolinite, muddy matrix, or authigenic quartz overgrowths ( Figure 6 ; Figure 7 ). The pores exhibit irregular morphologies, with diameters typically ranging from 10 to 30 μm.

② Secondary Dissolution Pores: These primarily comprise minor lithic and feldspar dissolution pores within grains, with lithic dissolution pores being dominant and feldspar pores less common. Intragranular dissolution pores occur in isolated or honeycomb patterns, and dissolution may follow cleavage planes within grains ( Figure 6 ; Figure 7 ). Pore diameters generally range from 20 to 70 μm, averaging approximately 30 μm.

③ Microfractures: Cast thin-section observations reveal sparse microfracture development. Although fracture density is low, fractures enhance pore connectivity in reservoir sandstones, serving as conduits for hydrocarbon migration. Overall, microfractures in the study area’s Benxi Formation are underdeveloped ( Figure 6 ; Figure 7 ).

④ Intracrystalline Pores: These pores vary in size and distribution, generally featuring small diameters influenced by crystal size and packing density. They primarily occur within clusters of authigenic clay minerals such as kaolinite, chlorite, and illite. Intracrystalline pore diameters are minute, typically less than 0.01 mm ( Figure 6 ; Figure 7 ). While intracrystalline pores contribute negligibly to overall storage capacity (comprising < 0.3% of areal porosity), they play a secondary role in enhancing micro-scale connectivity within clay-rich zones, potentially aiding fluid percolation in otherwise isolated pore networks dominated by intergranular and dissolution pores.

Statistical analysis indicates that the areal porosity of Benxi Formation sandstones ranges from 0.3% to 5.30%, averaging 3.6%. Pore types are dominated by volcanic lithic dissolution pores (0.2% - 4.8%, averaging 2.8%) and residual intergranular pores (0.3% - 4.3%, averaging 0.55%), with minor microfractures and intracrystalline micropores. The average areal porosity of microfractures and intracrystalline pores is approximately 0.3%.

High-pressure mercury intrusion commonly measures pore structure parameters, including those for throat size (displacement pressure and maximum throat radius; median pressure and median radius; average throat volume ratio), distribution (sorting coefficient, skewness coefficient, kurtosis), and connectivity (maximum mercury saturation and mercury expulsion efficiency) ( Zhang et al., 2024, 2020 ; Zhu et al., 2024 ).

For Benxi Formation sandstones, displacement pressure ranges from 0.01 to 1.54 MPa, averaging 0.71 MPa; median pressure from 1.98 to 69.46 MPa, averaging 20.29 MPa; and median radius from 0.10 to 0.37 μm, averaging 0.14 μm, indicating overall small pores but relatively larger throats. The sorting coefficient ranges from 0.05 to 4.43, averaging 2.43 (poor sorting); skewness from 0.11 to 0.77, averaging 0.31; and maximum mercury saturation from 62.55% to 96.76%, averaging 79.21%, signifying good connectivity. Overall, Benxi Formation sandstone throats are slightly small, poorly sorted, but well-connected ( Table 1 ).

Following the “Evaluation Methods for Oil and Gas Reservoirs (SY/T 6285–2011)” classification for clastic reservoir pore structures, analysis of mercury intrusion parameters, combined with petrophysical properties and capillary pressure curve shapes, delineates four throat structure types for Upper Paleozoic sandstones in the Yanchuan East Block ( Figure 8 ).

Type I (Low Displacement Pressure-Coarse Throat Type)

Capillary pressure curves for this type exhibit displacement pressures of 0.01 – 1.74 MPa (average 0.52 MPa), median pressures of 0.33 – 21.21 MPa (average 3.08 MPa), and average throat radii of 0.09 - 11.26 μm (average 1.73 μm). Skewness ranges from −0.22 to 2.49 (average 0.94, coarse-skewed); sorting coefficient from 0.14 to 0.33 (average 0.18); and maximum mercury saturation from 83.65% to 99.04% (average 92.22%). Curves trend toward the lower left with broad horizontal platforms ( Figure 8(a) ). Reservoirs of this type feature coarse throats with variable pore sorting. Porosity ranges from 2.10% to 9.00% (average 6.33%), and permeability from 0.057 to 4.723 mD (geometric mean 0.836 mD). These occur in composite-pore quartz sandstones dominated by residual intergranular pores with intense dissolution, where large and small pores coexist, throats are coarse, and connectivity is excellent, representing high-quality reservoirs. This type is common in the Benxi Formation.

Type II (Medium Displacement Pressure-Fine Throat Type)

Displacement pressures range from 0.01 to 6.32 MPa (average 0.60 MPa), median pressures from 0.27 to 36.15 MPa (average 4.66 MPa), and average throat radii from 0.02 to 6.66 μm (average 1.29 μm). Skewness ranges from −0.28 to 2.11 (predominantly coarse-skewed); sorting coefficient from 0.11 to 1.04 (average 0.30); and maximum mercury saturation from 72.90% to 95.80% (average 83.29%). Curves slightly trend lower left, with or without broad platforms ( Figure 8(b) ). Reservoirs feature fine throats with variable pore sorting. Porosity ranges from 1.82% to 11.57% (average 6.27%), but permeability is lower, from 0.016 to 4.143 mD (geometric mean 0.688 mD). These occur in quartz, lithic quartz, or lithic sandstones with dominant intergranular–lithic dissolution or intergranular–intracrystalline pore assemblages, intense dissolution, and moderate connectivity, representing good reservoirs. This type is widespread in the Benxi Formation.

Type III (Medium Displacement Pressure-Microfine Throat Type)

Displacement pressures range from 0.02 to 1.82 MPa (average 0.70 MPa), median pressures from 3.26 to 88.72 MPa (average 43.96 MPa), and average throat radii from 0.14 to 0.62 μm (average 0.34 μm). Skewness ranges from 0.90 to 2.69 (fine- to

coarse-skewed); sorting coefficient from 0.12 to 0.51 (average 0.27); and maximum mercury saturation from 63.40% to 91.26% (average 78.22%). Curves form steep slopes without platforms ( Figure 8(c) ). Porosity ranges from 0.80% to 1.63% (average 1.07%), and permeability from 0.012 to 1.681 mD (geometric mean 0.257 mD). These occur in lithic quartz or lithic sandstones dominated by intracrystalline or intragranular dissolution pores, with small pores, moderate sorting, and connectivity.

Type IV (High Displacement Pressure–Microfine Throat Type)

Displacement pressures range from 0.13 to 7.61 MPa (average 1.53 MPa), with median pressures exceeding 50 MPa; average throat radii from 0.02 to 0.20 μm (average 0.13 μm); skewness from -2.08 to 2.23 (predominantly fine-skewed); and sorting coefficient from 0.08 to 0.80 (average 0.32). Curves form convex upper-right steep slopes ( Figure 8(d) ). Porosity ranges from 1.79% to 5.30% (average 3.19%), and permeability from 0.003 to 0.131 mD (geometric mean 0.024 mD). Reservoirs feature micropores or intracrystalline pores, small throats, and poor connectivity, rendering them ineffective.

Core petrophysical analysis in the study area reveals that Benxi Formation reservoir porosity ranges from 0.17% to 9.07% (average 4.74%, median 3.83%). Most values (91.32%) fall between 2% and 7%, with 3.72% exceeding 7% and 4.96% below 2%. Permeability ranges from 0.01 to 6.05 mD (geometric mean 0.91 mD, median 0.06 mD), with 75.42% between 0.05 and 0.15 mD, 19.49% above 0.15 mD, and 5.08% below 0.05 mD ( Figure 9 ).

Per the “Norms for Estimation of Oil and Gas Resources (DZ/T 0217–2020)” petrophysical classification ( Table 2 ), reservoirs are categorized into six classes. Core data from the Yanchuan East Block show Benxi Formation overburden porosity of 3.0% - 14.9% (mean 5.4%, median 5.3%) and overburden permeability of 0.011 - 4.328 mD (median 0.078 mD). Thus, the block’s Benxi Formation sandstones classify as ultra-low porosity and tight reservoirs.

Thin-section, cast thin-section, SEM, XRD, and fluorescence analyses delineate diagenetic types and sequences for study area reservoir sandstones. Benxi Formation diagenesis divides into eodiagenesis and mesodiagenesis, with principal processes: mechanical compaction, cementation, and dissolution.

1) Mechanical Compaction

Compaction involves dewatering, porosity reduction, and volume decrease under overburden or tectonic stress post-deposition. Rigid grains (quartz, feldspar) undergo sliding, rotation, displacement, deformation, or fracturing, rearranging particles and altering structures; minor matrix fills pores. Post-intense compaction, Benxi Formation clastics are grain-supported, with rigid fragments showing line or concavo-convex contacts and severe primary intergranular pore destruction ( Figure 10(a)-(b) ). High plastic grain content (mica, mud clasts) leads to deformation or pseudomatrix formation, destroying primary pores ( Figure 10(c) , d). Sensitivity increases above 12% matrix, causing rapid compaction and pore loss. Plastic lithics like mica deform into pseudomatrix, reducing pores without cement ( Figure 10(e) ). Deeper burial transitions to pressure solution: quartz resists most, feldspar intermediately, lithics least. Quartz pressure solution forms overgrowths, consuming intergranular pores and degrading properties via enhanced contacts ( Figure 10(f) ).

2) Dissolution

Dissolution involves selective mineral removal during diagenesis to achieve physicochemical equilibrium, driven by environmental changes. Early dissolution relates to meteoric leaching; later to organic acids from kerogen maturation below

oil window depths. Observations show pervasive but moderate dissolution in the study area, targeting unstable lithics, carbonates, and cements, forming secondary pores. Selective dissolution causes uneven pore distribution ( Figure 11 ). In Benxi Formation reservoirs, feldspar-rich volcanic lithics undergo selective dissolution, forming secondary pores and enhancing properties. Minor lithic dissolution occurs in quartz sandstones; more in lithic quartz sandstones. This yields intergranular + intragranular pore assemblages ( Figure 11 ).

3) Cementation

Cementation precipitates minerals from pore fluids, binding sediments and reducing porosity/permeability. In the study area, it includes siliceous, carbonate, clay mineral, and pyrite types. Growth modes vary: overgrowths (e.g., silica on quartz), edge cements (clay rims), or infills (carbonates, zeolites).

① Siliceous Cementation

Silica supersaturation in pore fluids precipitates as quartz overgrowths or authigenic crystals on grain surfaces, or fine infills. Overgrowths show multiphase growth, thick and ubiquitous ( Figure 12(a)-(c) ), filling pores and clogging throats, impairing permeability ( Figure 12(d) ). Authigenic quartz, post-compaction, derives from feldspar/lithic dissolution or pressure solution, occurring as singles or aggregates ( Figure 12(e)-(f) ). It reduces primary pores and influences secondary ones. Siliceous cements average 1% - 5% in Benxi Formation reservoirs.

② Carbonate Cementation

Carbonates precipitate throughout diagenesis, varying in crystallography and composition due to fluid-rock interactions, pH, and redox conditions. Predominant calcite forms three phases.

I. Early Calcite Cementation

Micritic to microcrystalline carbonates precipitate from near-surface pore waters under low temperature/pressure when CaCO3 supersaturates in alkaline conditions. They form basal cements filling intergranular spaces, comprising calcite (occasional ferroan dolomite), 5% - 10% abundant, yielding calcareous sandstones. Grains float in cement with high intergranular volume, pre-compaction ( Figure 13 ).

II. Middle Carbonate Cementation

In late eodiagenesis, increased temperature/pressure compacts grains, reducing pore space to residual intergranular pores under weakly alkaline fluids. Supersaturation precipitates pore-filling cements ( Figure 14(a)-(b) ). Dispersed pore cements comprise ferroan calcite, clean and coarse-crystalline, 2% – 10%, forming calcic sandstones.

III. Late Ferroan Calcite Cementation

In mesodiagenesis, deep burial, high temperature/pressure, and reducing conditions enrich pore fluids in Fe²⁺/Mg²⁺ from clay alteration. Reduced CO₂ partial pressure incorporates ions into calcite/dolomite lattices. Late cements infill intergranular and dissolution pores as dispersed or granular ferroan calcite/dolomite, clean and fine-crystalline, 2% - 5% ( Figure 14(c)-(f) ). They postdate and replace earlier cements/quartz, marking the latest phase and contributing to late porosity reduction.

③ Authigenic Clay Mineral Cementation

Cast thin-sections, SEM, and XRD identify chlorite, kaolinite, illite-smectite mixed layers, and illite. Illite forms irregular, curved, or filamentous coatings on grains or fills fractures, with bridging in residual intergranular spaces. Chlorite occurs as early grain-coating films or late pore fills, with films predominant ( Figure 11(c) ). Minor platy or honeycomb illite-smectite fills intergranular pores or coexists with authigenic minerals, forming during deep burial. Kaolinite forms hexagonal platelets or aggregates in volcanic lithic pores, often with authigenic quartz ( Figure 12(e)-(f) ).

④ Pyrite Cementation

Minor pyrite forms early basal cements or late nodular/granular infills in intergranular pores, indicating enclosed reducing conditions during burial diagenesis ( Figure 15 ).

Quantitative estimation of porosity evolution, based on integrated thin-section porosity measurements, compaction modeling, and cement volume calculations, indicates that mechanical compaction accounts for approximately 40% - 50% of primary porosity loss (reducing initial −25% - 30% depositional porosity to −12% - 15%), while multiphase cementation (siliceous, carbonate, and clay) contributes 30% - 40% additional loss (further reducing to −5% - 8%). Conversely, selective dissolution during mesodiagenesis recovers 20% - 30% of porosity through secondary pore creation, partially offsetting densification and enabling localized reservoir enhancement.

Based on burial depth, rock fabric, pore types/assemblages, authigenic mineral sequences, clay assemblages, paleotemperature, organic maturity (vitrinite reflectance Ro, Tmax), hydrocarbon charge timing, diagnostic minerals in acidic/alkaline settings, and mineral-pore relations—integrated with regional geology—diagenetic stages are delineated using the following thresholds specific to the Ordos Basin context: eodiagenesis (burial depth < 2 km, temperature < 70˚C, Ro < 0.5%); mesodiagenesis A (burial 2 - 3.5 km, 70˚C - 120˚C, Ro 0.5% - 1.3%); and mesodiagenesis B (>3.5 km, >120˚C, Ro >1.3%).

1) Eodiagenesis

Shallow burial yields weak compaction, point-line grain contacts, and abundant primary pores (>25% porosity). Well-sorted barrier island sands have good pore-throat properties. Under early fluids, early calcite supersaturates in alkaline conditions as basal cement. Chlorite coats grains constructively, preserving pores. Zeolite cements precipitate as interlocking infills. Early compaction destroys −50% primary porosity.

In late eodiagenesis B, deeper burial intensifies compaction and cementation (quartz overgrowths, authigenic kaolinite). Contacts remain point-line; cements shift to pore-filling. Combined effects consolidate sandstones, reducing porosity to −15%.

2) Mesodiagenesis A

Early mesodiagenesis A sees low-maturity kerogen releasing organic acids, shifting to weakly acidic conditions. Selective dissolution of feldspars, volcanic lithics, and zeolites generates secondary pores, improving properties. Silica enters fluids, sourcing later quartz cements that overgrow grains, filling pores and clogging throats. This stage aligns with initial hydrocarbon charging in the Early Jurassic, where dissolution-enhanced pores begin trapping early-migrating gases from underlying coal measures.

3) Mesodiagenesis B

Intensified dissolution consumes acids, shifting to weakly alkaline conditions. Cementation strengthens with authigenic quartz and minor ferroan dolomite as pore-fills, further degrading properties. Late hydrocarbon charging in the Middle Jurassic to Early Cretaceous coincides with this stage, leveraging residual connected pore networks (from prior dissolution) for efficient gas accumulation and sealing against overpressured cements.