Effect of pore-throat structure and displacement pressure on gas distribution in tight sandstone reservoirs of the Lower Shihezi Formation in the Ordos Basin, China

To quantitatively analyze the effects of different displacement pressures and pore-throat structures on gas distribution characteristics, this study conducted multi-pressure gas displacement water NMR experiments and high-pressure mercury injection tests on twelve tight sandstone samples from the Lower Permian Shihezi Formation in the northern Ordos Basin. Based on the classification of pore-throat structures, quantitative analyses were performed. The study shows that four lithofacies are identified: braided channel base pebbly coarse-grained sandstone (Lpc), medial bar medium to coarse grained sandstone (Lmc), bar edge medium sandstone (Lm), and levee medium to fine grained sandstone (Lmf). The corresponding pore-throat structures and spatial types (nanopores, micropores and mesopores) are also determined. Mesopores are the primary storage spaces for gas, with an average gas saturation of 70%. At the microscopic level, median pore-throat radius (Rm), homogeneity coefficient (Hc), and sorting coefficient (Sc) significantly influence gas distribution within pore-throat of different sizes, while brittle mineral content and petrophysical parameters mainly affect gas content in mesopores. With increasing displacement pressure, the gas displacement rate in pores decreases exponentially, and at a displacement pressure of 6 MPa, the gas saturation of all types of reservoirs can reach 80% of the final gas saturation. Based on these findings, the gas distribution characteristics of various lithofacies of tight sandstones deposited by a continental braided river sedimentary system are established, identifying pebbly coarse-grained sandstone and medium-coarse sandstone as the optimal lithofacies for gas-bearing potential.

1 Introduction

Tight sandstone reservoirs possess substantial potential for natural gas storage and production, attracting increasing attention from petroleum geologists (Dai et al., 2012; Makeen et al., 2021; Yang et al., 2021; Song et al., 2024). The Ordos Basin, in particular, has become one of the most important sources of tight gas in China and a major focus of current research (Yang et al., 2008; Zhao et al., 2014; Tan et al., 2022; Jiang F. et al., 2023; Wu et al., 2023). However, the complexity of depositional environments and diagenetic evolution results in highly heterogeneous pore–throat structures. These differences further lead to significant variations in gas saturation across reservoirs in the basin (Qiao et al., 2019; Hui et al., 2020; Wang et al., 2020b; Yang et al., 2023; Zhou et al., 2022). Such strong variability in gas-bearing characteristics makes it crucial to quantitatively characterize gas distribution and elucidate the fundamental geological controls on gas occurrence within these reservoirs (Huyan et al., 2019; Wang et al., 2020a; Hui et al., 2020; Jiang L. et al., 2023). However, how gas saturation evolves dynamically within heterogeneous pore–throat systems under different displacement conditions remains insufficiently constrained, particularly in tight sandstones with complex lithofacies assemblages.

Previous studies have demonstrated that lithofacies types exert a primary control on pore–throat structures in tight sandstones (Feng et al., 2021; Huo et al., 2025; Liu et al., 2022; Qin et al., 2021; Zhao D. et al., 2022). Variations in sedimentary energy and depositional environments determine the original framework, grain-size distribution, and sorting characteristics of sand bodies, thereby influencing diagenetic pathways and subsequent pore–throat development (Lu et al., 2024; Su et al., 2024; Zhu et al., 2018). Lithofacies control both static petrophysical properties and dynamic displacement behavior (Dong et al., 2023; Feng et al., 2023; Huo et al., 2025; Jiang Z. et al., 2023). For instance, Makeen, et al. (2021) and Ding et al. (2025) reported that braided-channel sandstones, characterized by a strong supporting framework, exhibit higher displacement efficiency and better gas-bearing capacity, whereas fine-grained overbank sandstones show relatively poor displacement performance (Ding et al., 2025; Makeen et al., 2021). Therefore, conducting pore–throat structure research based on lithofacies classification provides a means to establish multiscale relationships from macroscopic depositional environments to microscopic pore systems and to reveal lithofacies-controlled differences in gas-bearing capacity (Xia et al., 2022; Zhao et al., 2024). Nevertheless, most existing studies remain focused on static pore–throat characteristics, and the lithofacies-controlled dynamic response of gas saturation to displacement processes has not been fully addressed.

Differences in pore–throat structure directly determine the gas-bearing characteristics of tight sandstone reservoirs (Li et al., 2025; Zhang et al., 2025). Systematic investigation of pore–throat systems can thus clarify the mechanisms by which pore–throat heterogeneity influences reservoir storage capacity, fluid migration, and gas enrichment, providing a theoretical basis for reservoir evaluation and development (Su et al., 2024; Zhang et al., 2019). At present, high-pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) are widely used in combination to characterize pore–throat structure and the distribution of movable fluids (Wen et al., 2023; Zhou et al., 2024). However, such studies mainly focus on the static distribution of movable fluids and cannot effectively simulate the dynamic migration and distribution of gas during charging and displacement processes (Feng et al., 2023; Li et al., 2017; Zhang et al., 2019). The pressure-dependent evolution of gas saturation across different pore–throat size scales, which is critical for understanding tight gas accumulation and productivity, remains poorly understood. Consequently, they fail to capture the true mechanisms of gas occurrence and saturation evolution in heterogeneous pore-throats systems. To overcome these limitations, multi-pressure gas displacement experiments have been introduced to simulate dynamic gas charging and displacement processes under realistic reservoir conditions. In recent years, gas displacement water nuclear magnetic resonance (GDWNMR) technology has emerged as an effective technique for simultaneously characterizing pore–throat structures and gas–water distribution under controlled displacement pressures. When integrated with HPMI, GDWNMR enables quantitative evaluation of gas saturation evolution across different pore–throat size scales, thereby revealing the influence of displacement pressure variations on gas occurrence within heterogeneous pore-throats systems. This integrated approach provides a unique advantage over conventional static methods by directly linking pore–throat structure, displacement pressure, and dynamic gas-bearing behavior.

Against this background, this study investigates the tight sandstones of the Lower Permian Shihezi Formation in the northern Ordos Basin, aiming to elucidate the coupling mechanisms among pore-throat heterogeneity, lithofacies characteristics, and reservoir gas-bearing capacity. Twelve sandstone samples were analyzed through HPMI and multi-pressure GDWNMR experiments. By integrating pore–throat classification, T₂ spectrum transformation, and quantitative analyses, this study aims to: (i) systematically clarify the gas distribution characteristics of different lithofacies reservoirs under various pore–throat sizes and displacement pressures; (ii) quantitatively assess the effects of displacement pressure, pore–throat configuration, and related factors on gas saturation and distribution; (iii) elucidate gas distribution patterns in tight sandstones deposited in continental braided-river systems. The results of this study provide new insights into the multiscale coupling between lithofacies, pore–throat structure, and gas-bearing behavior, offering a theoretical foundation for evaluating reservoir quality and guiding exploration and development of tight gas resources in similar continental depositional environments. By explicitly incorporating dynamic gas–water displacement processes into pore–throat characterization, this study extends conventional lithofacies-based analyses from static descriptions to dynamic gas-bearing evaluation.

2 Geological background

The Ordos Basin, located on the North China Craton, is the second-largest inland sedimentary basin in China (Figure 1a), covering an area of approximately 2.5 × 10⁵ km² (Wang et al., 2021; Zhang et al., 2023). It is also one of the country’s most important natural gas–rich regions, characterized by long-term tectonic stability and weak deformation (Su et al., 2021).

Figure 1

Figure 1. (a) Location map for the Ordos Basin in China. (b) Stratigraphic column of the Permian System in Dongsheng Gas Field, Ordos Basin (modified from Zhao et al., 2024).

During the Permian period, the collision between the North China and Yangtze plates transformed the basin from a marine depositional environment into a stable intracratonic basin (Liu et al., 2013; Yu et al., 2020). Structurally, the basin is relatively simple and can be subdivided into six major tectonic units: the Weibei Uplift, Yimeng Uplift, Jinxi Fold Belt, Western Thrust Belt, Yishan Slope, and Tianhuan Depression (Duan et al., 2008; Xiao et al., 2005).

The study area is located in the Hangjinqi region in the northern part of the Yimeng Uplift, within the Dongsheng Gas Field. The structural setting of this area is relatively stable and gentle, with very limited fault development. The overall structure exhibits a gentle northeast-to-southwest dip, forming a broad monoclinal structure and a stable stratigraphic distribution (Figure 1b). As of 2024, the proven natural gas reserves in the Paleozoic formations of the Dongsheng Gas Field have reached 2.52 × 10¹⁰ m³, making it one of the key gas accumulation zones in the northern Ordos Basin. The target formation of this study is the Lower Shihezi Formation, which represents the primary gas-bearing interval in the Dongsheng Gas Field. The formation was deposited in a continental braided river system with sediment provenance predominantly from the northwest, forming a composite depositional system characterized by the superposition of multi-stage sand bodies under a braided fluvial setting. The reservoir mainly comprises deposits of braided channels, bars, and levees. Prior to Late Cretaceous gas charging, the reservoir had already evolved into the middle diagenetic stage B, representing a typical “densification before hydrocarbon accumulation” development model (Zhao D. et al., 2022). In addition, the field is characterized by relatively high water production compared with other gas fields in the Ordos Basin, with an average water production of approximately 15 m³/d per well. Therefore, clarifying the influence of different lithofacies types and their pore–throat structures on gas-bearing properties is critical for guiding future development of this gas field.

The tight sandstone samples analyzed in this study were collected from the Lower Shihezi Formation in the Hangjinqi area of the northern Ordos Basin. These samples are representative of the primary gas-bearing intervals and the major lithofacies types in the region.

3 Samples and methods

3.1 Samples

Core observation and description of the tight sandstone reservoirs from the Lower Shihezi Formation were conducted on 11 drilled wells within the J58 block. Twelve representative cylindrical core plugs were collected for analysis (Table 1). Each plug has a diameter of 2.5 cm and an approximate length of 5 cm. Prior to petrophysical testing, all samples were thoroughly cleaned to remove residual hydrocarbons and impurities.

Table 1

Table 1. Porosity, permeability, and mineral composition and contents of 12 samples.

3.2 Methodology

3.2.1 Porosity, permeability, and XRD analysis

Porosity and permeability measurements of the selected core samples were conducted using a CMS-300 porosity and permeability analysis system at the State Key Laboratory of China University of Petroleum (Beijing), following the industry standard SY/T 5336-2006. X-ray diffraction (XRD) analyses were performed using a D8 DISCOVER diffractometer, and the experimental procedures adhered to the national standard SY/T 5163-2018.

3.2.2 CTS and SEM

Twelve thin sections (0.03 mm in thickness) of tight sandstone samples were prepared as polished casting slices. After impregnation with blue epoxy resin, petrographic observations were conducted using a polarizing microscope to characterize lithofacies features and pore–throat structures, following the industry standard SY/T 5368-2016. Subsequently, scanning electron microscopy (SEM) was employed to analyze the microscopic characteristics of clay-mineral-related pore–throat structures, cements, and intercrystalline micropores, with a maximum resolution of up to 1.2 nm.

3.2.3 Gas displacement water NMR measurements

The gas displacement water nuclear magnetic resonance (GDWNMR) experiments were conducted using an integrated testing system consisting of a core holder, NMR detection unit, gas monitoring device, pressure pump, nitrogen cylinder, pressure stabilizer, and data acquisition system (Figure 2). The experiments were performed on a MARAN-DRX/2 NMR spectrometer under the following parameters: resonance frequency of 2.38 MHz, echo spacing of 0.1 ms, 128 scans, waiting time of 3 s, and 17,500 echoes, with the temperature maintained at 25 °C throughout the process. The experimental procedure was as follows: First, the tight sandstone samples were dried at 105 °C for 72 h to remove residual moisture and hydrocarbons. The samples were then vacuumed and saturated with simulated formation water (salinity = 22.357 mg/L) for 7 days to ensure full pore saturation and minimize salinity effects. The mass of the water-saturated samples was recorded, and an initial NMR measurement was performed. Subsequently, the saturated samples were placed in the core holder, and a confining pressure of 12 MPa was applied to simulate in situ reservoir stress conditions. After confirming the system’s seal integrity, nitrogen gas was injected in stages at displacement pressures of 2, 4, 6, 8, and 10 MPa until the irreducible water saturation state was reached. After each displacement stage, the T₂ relaxation spectrum of the sample was measured at 25 °C. Upon completion of the displacement experiments, the samples were centrifuged at 400 psi to remove all remaining movable fluids. After confirming the absence of movable fluids, a final T₂ measurement was conducted. In this study, the T₂ distributions of the samples were measured under three conditions: brine-saturated, after gas displacement at different pressures, and after complete centrifugation.

Figure 2

Figure 2. Schematic diagram of the gas displacement water nuclear magnetic resonance experiment setup.

3.2.4 HPMI

High-pressure mercury intrusion (HPMI) experiments were conducted using an AutoPore IV9505 porosimeter, with a maximum injection pressure of up to 200 MPa, to characterize the pore system under high-pressure conditions and quantitatively reveal the distribution and structural differences of pore-throat radii. As the mercury injection pressure gradually increased, mercury was forced into the connected pore system. Upon reaching the maximum pressure, the pressure was gradually released to allow mercury withdrawal, thereby obtaining complete mercury intrusion–extrusion curves.

The relationship between capillary pressure and pore-throat radius is described by the Washburn equation (Washburn, 1921):

$P=\frac{2\sigma \cos \theta }{r}(1)$

where P is the capillary pressure (MPa), r is the pore-throat radius (μm), θ is the contact angle (140°), and σ is the mercury–air interfacial tension (0.48 N/m). Based on Equation 1, the pore-throat size distribution and other key parameters characterizing the pore structure can be derived, thereby providing a quantitative basis for evaluating pore-throat structure characteristics and connectivity in tight sandstone reservoirs.

3.2.5 Transforming NMR T₂ spectrum into pore-throat size distribution

The distribution characteristics of the T₂ spectrum intuitively reflect the fluid occupancy state within pores and are closely related to the pore–throat structure of the reservoir. Therefore, in this study, high-pressure mercury intrusion (HPMI) data and nuclear magnetic resonance (NMR) measurements under water-saturated conditions from the same samples were integrated to comprehensively characterize the pore–throat structure distribution. Specifically, NMR measurements were first conducted under fully water-saturated conditions to obtain the T₂ spectrum, and its cumulative amplitude percentage curve was calculated to represent the cumulative pore-volume fraction associated with different relaxation times. In parallel, HPMI experiments were performed on the same samples to derive the cumulative mercury saturation curve as a function of pore–throat radius, which characterizes the cumulative distribution of pore–throat sizes controlling mercury intrusion (Figure 3a). The transverse relaxation time (T₂) of fluids in pores can be expressed in simplified form as (Kleinberg and Horsfield, 1990):

$\frac{1}{T_2}\approx {\rho }_2\frac{S}{V}=\frac{1}{{\rho }_2{F}_{s}r}(2)$

where F_s is the pore shape factor and r is the pore–throat radius. Experimental evidence indicates that, for a given core sample, ρ₂ and F_s can be considered constants, leading to a power-law relationship between T₂ and r. Accordingly, Equation 2 can be rewritten as:

$r=C{T}_2^{1/n}(3)$

where C and n are fitting parameters representing the surface relaxation properties and the structural complexity of the pore–throat system, respectively.

Figure 3

Figure 3. (a) Workflow for converting NMR T₂ spectra into pore–throat size distribution based on HPMI results; (b) Diagram of the method of converting the T₂ spectrum into pore-throat size distribution of sample 4; (b) Method of obtaining the C and n values of sample 4; To determine the parameters C and n, the cumulative amplitude percentage curve of the NMR T₂ spectrum was first calculated. Meanwhile, the cumulative mercury saturation curve as a function of pore–throat radius was obtained from HPMI data. These two cumulative frequency curves were then matched on a one-to-one basis, and the corresponding T₂(i) and r(i) values under identical cumulative probability S(i) were derived through vertical interpolation (Figure 3b). Finally, by fitting the experimental r(i) values from HPMI with the corresponding T₂(i) values using Equation 3, the parameters C and n were obtained, establishing a quantitative conversion relationship between T₂ and r (Figure 3c).

This method effectively integrates NMR relaxation characteristics with pore–throat structure parameters, providing a theoretical foundation for the quantitative identification of pore–throats and multiscale pore structure characterization. Ultimately, the water-saturated T₂ spectra were converted into pore–throat size distribution curves. Based on pore–throat radius, the pores were classified into three categories: mesopores (0.1–1 μm), micropores (0.01–0.1 μm), and nanopores (<0.01 μm).

At different displacement pressures, gas entering the pore-throat causes changes in the fluid volume, resulting in variations in the NMR T₂ spectrum measured after gas displacement. Since the total volume of the sample’s pore-throat remains constant, the variation occurs in the distribution of fluids within the pore-throat. Therefore, by dividing the values of each point of the T₂ spectrum obtained after gas displacement at different pressures by the cumulative value of the NMR T₂ spectrum of water saturated samples and summing the results, the cumulative probability curve can be obtained after water displacement by gas. The difference between this curve and the cumulative probability curve of water-saturated samples represent the cumulative probability of gas distribution within the pore-throat.

4 Results

4.1 Pore-throat characteristics

The pore–throat structures of the tight sandstone samples from the Lower Shihezi Formation in the J58 well block, Hangjinqi area of the Ordos Basin, were systematically analyzed using CTS and SEM (Figure 4). The results show that the reservoir contains a wide variety of pore types, including intergranular pores, dissolution pores, intercrystalline pores, and microfractures. In addition, two types of throats—sheet throats and curved sheet throats—were identified. These pores and throats exhibit significant differences in origin, morphology, and connectivity. Residual intergranular pores are among the most common primary pore types, typically showing irregular polygonal shapes and partially filled with authigenic quartz, calcite, or clay minerals. They generally form in zones where late-stage cementation is incomplete, resulting in relatively large pore sizes that serve as the main gas storage spaces (Figures 4a,f). However, local occurrences of calcite cementation replacing quartz or clay mineral infilling can reduce throat size and connectivity (Figure 4b). Dissolution pores occur in two forms: intragranular and intergranular. The former primarily develop within feldspar grains as a result of acidic diagenetic fluid leaching (Figure 4c), while the latter usually form in areas where early calcite or other cements have been dissolved, showing irregular morphologies (Figure 4d). Intercrystalline pores mainly develop between clay minerals such as kaolinite, chlorite, and illite/smectite mixed-layer minerals. The platy structure of kaolinite creates regular intercrystalline voids, whereas chlorite commonly aligns along grain surfaces, forming micro-to nano-scale pores (Figures 4f,g). Although small in size, these pores are abundant and uniformly distributed, forming an essential part of the micropore system that significantly influences gas adsorption and capillary transport. Microfractures are locally observed along mica cleavages or grain boundaries, appearing as irregular linear features typically less than 10 μm in width (Figure 4h). Although their overall development is sparse and their impact on reservoir permeability is limited, they indicate minor modifications to the pore system caused by late-stage tectonic stress. Sheet throats generally occur between residual intergranular pores. Due to relatively flat grain contacts, the throats exhibit a parallel, sheet-like geometry and are typically preserved remnants of primary throats formed after early compaction. They possess good connectivity and serve as the main channels for fluid migration within the reservoir (Figure 4i). Curved sheet throats commonly coexist with intergranular pores. Under compaction, grains become more tightly packed, leading to localized bending or narrowing of throats and forming irregular, curved channels. These throats usually extend along grain boundaries and, although prone to deformation or partial closure under stress, they still maintain partial connectivity within the pore system.

Figure 4

Figure 4. CTS and SEM images of the Lower Shihezi reservoir in the J58 area. (a) Residual intergranular pores (Sample 9); (b) Intragranular dissolution pores and calcite cement (Sample 6); (c) Intergranular dissolution inside feldspar and calcite cement (Sample 7); (d) Kaolinite inter-crystaline pores and residual intergranular pores (Sample 12); (e) Inter-crystalline micropores, SEM (Sample 9); (f) Development of autogenous quartz, residual intergranular pores and chlorite inter-crystalline pores, SEM (Sample 3); (g) Inter-crystalline pores formed between chlorite and illite, SEM (Sample 8); (h) Microfracture and mica bedding microfracture formed by strong compaction (Sample 11). (i) Sheet and curved sheet throats formed or modified by compaction (Sample 1).

4.2 Lithofacies, petrophysical, and mineralogy

Based on core description, well logging, thin-section petrography, and mineral composition analysis, the tight sandstones formed by braided river deposition in the study area were classified into four distinct lithofacies types.

4.2.1 Pebbly coarse-grained sandstone with massive bedding (Lpc)

The Lpc primarily occurs above the erosional surfaces at the base of channel-fill deposits. It is mainly composed of thick-bedded gray to brownish-gray coarse-grained sandstones, occasionally interbedded with conglomeratic layers (Figures 5a1–a7). The sandstone exhibit a grain-supported texture, and the dominant pore type is residual intergranular pores. X-ray diffraction (XRD) analysis shows that this lithofacies contains the highest quartz content (average 63.7%), relatively low clay content (15.1%), and minimal carbonate minerals (6.6%), indicating excellent reservoir quality (Table 1). The average porosity and permeability are 13.7% and 7.4 mD, respectively, making this lithofacies the most favorable reservoir type in the study area.

Figure 5

Figure 5. Characteristics of four lithofacies determined using logging curves, petrophysical properties, cores images and CTS. (a1–d1) Lithology columns; (a2–d2) GR curves; (a3–d3) RT curves; (a4–d4) Core-measured porosity; (a5–d5) Core-measured permeability; (a6–d6) Core photographs; (a7–d7) CTS images.

4.2.2 Medium to coarse-grained sandstone with parallel bedding (Lmc)

The Lmc lithofacies is widely developed in the middle parts of mid-channel bars and consists of gray to brownish-gray medium–coarse-grained sandstones with well-developed parallel lamination, indicative of relatively stable hydrodynamic conditions and a moderately to highly energetic depositional environment (Figures 5b1–b7). Compared with the Lpc lithofacies, its reservoir quality is slightly inferior. Quartz content remains high (62.3%), but feldspar and clay contents are slightly increased, with carbonates averaging 10.1% (Table 1). Under the microscope, a few relatively large intergranular pores are observed, suggesting moderately good pore preservation.

4.2.3 Medium grained sandstone with parallel or ripple lamination (Lm)

The Lm lithofacies mainly consists of gray, medium-grained sandstones. It exhibits parallel or ripple lamination and occurs primarily along the margins of mid-channel bars, representing a lower-energy depositional setting (Figures 5c1–c7). This lithofacies has an average porosity of 8.5% and permeability of 4.0 mD, reflecting moderate reservoir properties. The mineral composition includes relatively high quartz content (61.2%) and increased feldspar content (21.9%), with clay minerals accounting for 11.6% (Table 1). A few dissolution pores are visible under the microscope; however, the overall pore–throat structure is significantly influenced by clay minerals.

4.2.4 Medium to fine grained sandstone with horizontal bedding (Lmf)

The Lmf consists of gray, medium to fine grained sandstones with thin horizontal bedding, representing a low-energy overbank depositional environment (Figures 5d1–d7). This lithofacies exhibits the poorest reservoir quality, with an average porosity of 3.0% and permeability of 1.9 mD. It has the highest clay (23.7%) and carbonate (9.0%) contents, whereas quartz and feldspar contents are relatively low (Table 1). The high proportion of argillaceous material severely restricts pore development; only a few residual pores are visible under the microscope. This lithofacies represents the densest and least permeable reservoir type in the study area.

4.3 HPMI results

The pore–throat structures of the four lithofacies in the J58 block exhibit significant heterogeneity, as evidenced by variations in capillary pressure curves and pore–throat structural parameters. Accordingly, the tight sandstones in the study area can be classified into four pore–throat types (Type I–IV), each corresponding to a specific sedimentary lithofacies.

The representative pore–throat characteristics of the four lithofacies indicate distinct structural features. Type I (Lpc) samples display a relatively gentle capillary pressure curve, with most mercury injection pressures concentrated below 1 MPa (Figure 6a1). The threshold pressure (Pt) is generally low, averaging 0.21 MPa, and the mean pore–throat radius reaches 0.59 μm, suggesting well-developed pore–throat systems with good connectivity (Table 2). The pore–throat size distribution exhibits a typical bimodal pattern (Figure 6a2), dominated by larger pore–throats, indicative of high permeability and efficient fluid flow pathways. Type II (Lmc) samples show slightly steeper capillary pressure curves, primarily distributed above 1 Mpa (Figure 6b1). The pore–throat radius ranges between 0.007 and 0.2 μm, with an average of 0.30 μm. The pore–throat structure is relatively homogeneous, characterized by a unimodal distribution (Figure 6b2). Overall, the development of the pore–throat network is slightly inferior to that of Type I, reflecting moderately reduced connectivity and fluid transmissibility. Type III (Lm) samples exhibit capillary pressure curves composed of two short segments, and the corresponding pore–throat distribution also displays a bimodal pattern with comparable proportions of the two peaks (Figure 6c). The pore–throats in this lithofacies are smaller and more dispersed, with a low mercury withdrawal efficiency (28.6%), indicating poor connectivity and limited flow capacity. Type IV (Lmf) samples also show a bimodal pore–throat distribution curve; however, the dominant peak is located on the left side (Figure 6d), corresponding to fine-scale pore–throats. The average pore–throat radius is the smallest (0.22 μm), representing the tightest reservoir type. This lithofacie is characterized by extremely poor connectivity and the weakest overall flow capacity among the four types.

Figure 6

Figure 6. Characteristics of HPMI curves and pore-throat distributions in four typical tight sandstones. (a1–d1) HPMI curves of four typical pore-throat; (a2–d2) Pore-throat distributions and permeability contribution of four typical pore-throat.

Table 2

Table 2. Pore-throat structure parameters and movable volume parameters obtained from high-pressure mercury injection and nuclear magnetic resonance.

4.4 NMR results

Under fully water-saturated conditions, the T₂ distribution curves of the 12 samples are shown in Figure 7. Except for Sample 4, which exhibits a single dominant peak with a large amplitude, the remaining samples generally display bimodal T₂ spectra. However, variations in peak position and distribution range indicate significant differences in pore–throat structures among the various sample types. Overall, as the pore–throat structure evolves from Type I to Type IV, the main peak of the T₂ distribution curve progressively shifts toward shorter relaxation times, with decreasing amplitude and narrowing curve width. This trend reflects a reduction in pore–throat size, a decline in pore development, and a gradual deterioration of connectivity. Type I pore–throat structures are characterized by strong signal intensity and a wide distribution range, extending from 0.01 to 1,000 ms. Notably, Samples 6 and 12 exhibit two parallel dominant peaks, whereas Sample 9 shows the most pronounced variation in incremental porosity, reaching a maximum of 0.315%. With the progressive degradation of the pore–throat structure, the T₂ spectral range and amplitude decrease, and the dominant peak gradually shifts leftward. In Type IV pore–throat structures, the main peak is located within the shortest relaxation time interval (<0.5 ms). Among all samples, Sample 3 exhibits the smallest incremental porosity amplitude, measuring only 0.041%.

Figure 7

Figure 7. The T₂ spectrum of 12 studied sandstone samples obtained from the nuclear magnetic resonance experiment.

4.5 Pore-throat structure

Based on Equation 3 and the corresponding conversion process (Figure 3), the T₂ spectra of the 12 samples were transformed into pore–throat size distribution curves (Figure 10). Integrating scanning electron microscopy (SEM) image analysis with NMR experimental results, the pore–throat systems were classified into three categories from the perspective of gas occurrence space within pores and throats, using 0.01 μm, 0.1 μm, and 1 μm as the classification boundaries. The proportions of different pore–throat size classes were then quantified (Figure 8).

Figure 8

Figure 8. The proportion of porosity contributed by pore-throats types of various scales.

The results indicate that most samples are dominated by micropores, while Sample 1 shows the highest proportion of nanopores (Figure 8). In Samples 7 and 8, the proportions of the three pore–throat types are relatively balanced. For Type I pore–throat structures, micropores account for an average of 56%, mesopores about 28%, and nanopores approximately 15%. In Type II, the proportion of nanopores increases to an average of 23%. Type III pore–throat structures exhibit pronounced heterogeneity, with micropores being dominant (38%), and mesopores and nanopores showing similar proportions of 29% and 31%, respectively. In Type IV structures, mesopores are least developed, accounting for only 8%, whereas nanopores dominate with an average proportion of 46%. Overall, from Type I to Type IV pore–throat structures, there is a clear trend of increasing nanopore proportion, reflecting a progressive transition of the reservoir pore system from larger to finer pores, corresponding to enhanced structural compactness and reduced reservoir quality.

4.6 Gas distribution results

4.6.1 Gas content inside pore-throats of full-size

The NMR T₂ spectrum primarily reflects the volumetric distribution characteristics of fluids within pore–throat systems, while its converted distribution curve represents the spatial occurrence of these fluids within the pores and throats. Therefore, the variation in fluid volume induced by gas displacement under different pressures can be directly correlated with the gas-occupied porosity (Pog). In this study, the T₂ spectra of 12 samples were converted into pore–throat radius distribution curves. Combined with the results of the gas displacement water NMR (GDWNMR) experiments (Figure 9), the variations in fluid volume under different displacement pressures were quantified. By comparing the pore–throat distribution curves between the water-saturated and gas-displaced states, the Pog of full size pore-throats corresponding to each displacement pressure were determined.

Figure 9

Figure 9. Nuclear magnetic resonance T₂ spectrum of water saturated conditions, gas displacement water at different pressures, and centrifugal conditions. (a) Sample 4, Type I pore-throat structure; (b) Sample 11, Type III pore-throat structure; (c) Sample 8, Type II pore-throat structure; (d) Sample 3, Type IV pore-throat structure.

The results indicate that P_og gradually increases with rising displacement pressure (Table 3). When the displacement pressure reaches 10 MPa, the P_og values for all pore–throat types attain their maxima. Overall, Type I samples exhibit the highest gas charging capacity, with the average gas-occupied porosity (P_og) increasing from 1.66% to 4.17% and the gas saturation (S_g) rising from 12.0% to 30.1%. Among them, Sample 6 is the most representative, showing a P_og of 5.65% and an Sg of 38.8% at 10 MPa, indicating well-connected pore–throat structures, sufficient storage space, and the highest gas displacement efficiency. Type II samples show moderate gas charging capacity, with average P_og and S_g increasing to 2.48% and 27.4%, respectively; for instance, Sample 11 reaches an S_g of 28.0% at 10 MPa. Type III samples display smaller increments, with a maximum S_g of only 18.5%, suggesting limited gas expansion. Type IV samples exhibit the lowest values, with average Sg increasing from 9.8% to 18.0%, and only Sample 2 showing slight improvement under high pressure (S_g = 28.4%). Overall, gas displacement efficiency is closely related to pore–throat structure—the more complex the pore–throat system, the poorer the displacement performance and gas-bearing capacity.

Table 3

Table 3. Gas-occupied porosity (P_og) and gas saturation (S_g) of samples under different displacement pressures.

4.6.2 Gas content inside pore-throats of different sizes

The NMR T₂ spectrum primarily reflects the fluid volume within the pore-throat. The transformed distribution curve represents the fluid distribution characteristics. Therefore, the changes in fluid volume after gas displacement at different pressures directly correspond to P_og. Based on Equation 3 and the conversion process depicted in Figures 4, 5, the T₂ spectrum of the 12 samples was first transformed into pore-throat size distribution curves using the multi-stage fitting method. Then, the changes in fluid volume after gas displacement at different pressures are obtained by combining the results of GDWNMR (Figure 10). By analyzing the difference between the pore-throat distribution curves under water saturated conditions and after water displacement by gas, the P_og under different displacement pressures can be determined. As the displacement pressure increases, the P_og gradually increases (Table 4). Under a displacement pressure of 10 MPa, the P_og reaches its maximum value for all pore-throat sizes, with the highest P_og observed in sample 6 with pore-throat sizes ranging from 0.1 to 1 μm, reaching 3.46%. Significant differences also exist in the distribution of S_g and S_pt within pore-throat of different radius (Table 5). According to the classification based on pore-throat size, at gas displacement pressure of 2 MPa, the S_g in pore-throat ranging from 0.001 to 0.01 μm is relatively low, ranging from 0.17% to 1.85%. The corresponding distribution range of S_pt within pore-throat varies from 0.17% to 1.85%. Conversely, at a displacement pressure of 10MPa, the S_g within pores ranging from 0.1 to 1 μm is the highest, indicating the best displacement efficiency, ranging from 3.38% to 23.76%. The distribution range of S_pt within pore-throats ranges from 52.99% to 86.84%.

Figure 10

Figure 10. The distribution of fluids within samples with four different pore-throat structures after varying displacement pressures. (a) Sample 11, Type I pore-throat structure; (b) Sample 8, Type II pore-throat structure; (c) Sample 11, Type III pore-throat structure; (d) Sample 2, Type IV pore-throat structure.

Table 4

Table 4. Gas-occupied porosity (P_og) in different sizes of pore-throat under different displacement pressures.

Table 5

Table 5. Gas saturation (S_g) and gas saturation inside pore-throat (S_pt) under different displacement pressures.

5 Discussion

5.1 Factors affecting gas distribution

5.1.1 Diagenetic minerals

Gas-occupied porosity (P_og) shows a strong positive correlation with lithofacies and specifically the quartz content, a weak negative correlation with carbonate cement content, and a strong negative correlation with clay mineral content, although the correlation with feldspar content is not significant (Figure 11a). The high-energy hydrodynamic conditions ensured the purity of the sandstone, providing space for gas accumulation. In Lpc formed under high-energy hydrodynamic deposition, samples 4 and 6 exhibit higher quartz content, resulting in relatively high P_mv, which offers favorable conditions for gas preservation. This phenomenon reflects that fact that the quartz and clay mineral content in diagenetic minerals primarily influence displacement results. Brittle mineral particles are less affected by lithostatic pressure, favoring the retention of intergranular pores (Wang et al., 2020c; Wang et al., 2023; Zhao S. et al., 2022). Consequently, as gas displacement pressure increases, P_og gradually increases, ultimately approaching the movable pore volume (Figure 11a). Previous studies have suggested that feldspar dissolution facilitates the formation of secondary porosity (Ma et al., 2017). However, this study reveals a weak negative correlation between feldspar content and gas distribution. This is because clay minerals generated during the kaolinitization of feldspar reduce reservoir connectivity, which is unfavorable for gas displacement. Secondly, although feldspar may develop dissolution pores internally, its poor connectivity has a minimal overall impact on P_og after sample displacement. Clay minerals mainly fill dissolution pores and residual intergranular pores, enhancing the heterogeneity of tight sandstone reservoir pore-throat structure and reducing reservoir connectivity, thereby decreasing the gas content after gas displacement water.

Figure 11

Figure 11. Pearson correlation matrix of multiple control factors that affect the gas-occupied porosity (P_og) under different displacement pressures. (a) Diagenetic mineral and reservoir physical properties. (b) Pore-throat structure and reservoir heterogeneity parameters.

It is noteworthy that, apart from chlorite, other single clay mineral contents have minimal impact on reservoir fluid flow (Figure 11a). This indicates that the formation of chlorite films plays a positive role in preserving intergranular pores, improving reservoir quality, and facilitating gas storage in the reservoir. Well-developed chlorite can retain up to 20% porosity, as similarly demonstrated in the Cretaceous sandstones of the Sawan Gas Field in Pakistan ((Berger et al., 2009). However, the distribution of gas within the reservoir is influenced by multiple clay minerals collectively, and overall clay mineral development can deteriorate reservoir properties. A higher clay mineral content can lead to reduced reservoir mobility. In Lmf, which develops at the channel overbank under weaker hydrodynamic conditions, the clay mineral content is relatively high, resulting in limited movable pore-throat space and, consequently, poorer gas-bearing capacity of such reservoirs. Additionally, with increasing displacement pressure, the migration of clay minerals can block small-sized throats, similarly leading to a deterioration in displacement effects, thereby strengthening the negative correlation (Figure 11a).

The impact of diagenetic minerals on P_og within different pore-throat sizes is substantial (Figure 12). Previous studies suggested that quartz content contributes to the overall preservation of reservoir pores, thereby increasing gas saturation in gas reservoirs (Dong et al., 2023; Jiang M. et al., 2023; Wang et al., 2024). However, this study found that quartz content has the most significant impact on gas distribution within mesopores and micropores. This indicates that the compressive strength of quartz primarily preserves intergranular pores, particularly mesopores and micropores. The good connectivity of these pore-throat types allows gas displacement within them and facilitating gas storage. Feldspar, on the other hand, significantly affects P_og within micropores, showing an overall weak negative correlation (Figure 12).

Figure 12

Figure 12. Pearson correlation matrix of various controlling factors affecting the gas-occupied porosity (P_og) in different pore-throat sizes under different gas displacement water pressures.

This indicates that the dissolution pores within feldspar are primarily micropores, but their poor connectivity reduces the proportion of gas-filled pores in these micropores. Clay minerals, acting as inhibitors of fluid flow, increase the specific surface area of rocks, enhancing the interaction between rock particle surfaces and fluids. On the other hand, clay minerals are key factors contributing to reservoir sensitivity, leading to reservoir damage and restricting fluid mobility (Wang et al., 2020c; Zhao S. et al., 2022). Studies have shown that the development of clay minerals has adverse effects on pore-throat structures of various sizes (Figure 12). Carbonate minerals are generally considered to fill intergranular spaces through cementation, occupying fluid flow pathways and inhibiting fluid mobility. This study demonstrates that carbonate cementation primarily affects the gas saturation of mesopores. The development of carbonate cement reduces mesopore connectivity, thereby decreasing gas distribution in these pores. Additionally, dissolution pores within carbonate cementation are predominantly found in micropores and nanopores, increasing the proportion of these pore types. As a result, there is a weak positive correlation between carbonate cement content and gas saturation in micropores and nanopores.

5.1.2 Reservoir physical properties

Many studies have shown that permeability correlates better with reservoir gas-bearing capacity evaluation indicators than porosity (Yang et al., 2020; Zhang et al., 2022). However, this study reveals that the influence of porosity and permeability on reservoir gas-bearing capacity is pressure-dependent. As displacement pressure increases, the correlation between P_og and porosity strengthens (Figure 11a). This suggests that higher displacement pressure allows gas to displace a larger volume of fluid, ultimately approaching the volume of movable fluid, resulting in higher gas saturation. In contrast, as displacement pressure increases, the correlation between permeability and P_og gradually weakens. This indicates that with higher gas displacement pressure, more fluid in micropores and nanopores is displaced by gas. The influence of narrow throats and hydrophilic mineral particles on fluid retention diminishes, leading to reduced effects on pore-throat connectivity and permeability. Therefore, with increasing displacement pressure, the correlation between porosity and reservoir gas-bearing capacity gradually improves, while the influence of permeability on reservoir gas-bearing capacity diminishes.

Under different displacement pressures, P_og in mesopores exhibits a strong positive correlation with both porosity and permeability (Figure 12). However, as pore-throat size decreases, the influence of physical properties on gas saturation within pore-throats gradually diminishes. Specifically, the average correlation coefficient of porosity decreases from 0.88 to 0.29, and that of permeability drops from 0.94 to 0.21. This is because mesopores and micropores contribute the most to overall porosity and permeability, making them the primary targets for gas injection during the charging process.

5.1.3 Pore-throat structure and heterogeneity

The type, shape, size, distribution, and various combinations of the pore-throat structure, along with their degree of development, all influence the complexity of reservoir pore-throat structure, influencing reservoir connectivity and directly affecting the distribution characteristics of gas within a reservoir (Liu et al., 2023; Zhang et al., 2022). The correlation between pore-throat structure and heterogeneity parameters with the distribution of gas within full-size pore-throat is seen in Figure 11b. The results show that R_m is the most reliable parameter in evaluating gas-bearing characteristics, followed by R_a, with R_max being the least reliable. The R_max exhibits a weak positive correlation with Pog on the whole, whereas R_a demonstrates a strong positive correlation, and both correlations tend to weaken with increasing displacement pressure. The difference lies in that R_max reflects the maximum value of pore-throat within the reservoir, which has limitations in reflecting pore-throat size (Figure 11b). With increasing displacement pressure, fluids within pore-throat of different sizes are gradually displaced by gas, enhancing reservoir connectivity and directly leading to a further reduction in the correlation of this parameter. On the other hand, the R_a can reflect the concentration trend of pore-throat sizes but poorly reflects the distribution characteristics of pore-throat. Therefore, as more pore-throat become gas-connected, the correlation between P_og and R_a gradually weakens. It can be observed that P_og within mesopores is significantly influenced by R_max and R_a, with a stronger correlation with R_a than R_max (Figure 12). Conversely, R_m, which reflects the distribution characteristics of pore-throats sizes well, affects P_og within all three pore-throat size categories. This viewpoint is clearly supported by the parameters of Lm and Lmc. Although Lm, deposited along the edge of bars, exhibits well-developed mesopores—leading to higher Rmax and Ra values than Lmc—comparative gas displacement results demonstrate that Lm possesses superior gas-bearing properties, with P_og values of 2.48% and 1.56%, respectively. These findings suggest that more homogeneous pore-throats structure is more conducive to gas storage. The R_m reflects the distribution characteristics of pore-throat sizes within the reservoir, and P_og distribution is controlled by the size distribution of pore-throat. Thus, as displacement pressure increases, the correlation between P_og and R_m increases. Considering these three pore-throat size parameters together, P_og is primarily controlled by R_m. Gas distribution within pore-throat of different sizes validates these points.

The P_t obtained from mercury injection exhibit a weak negative correlation with P_og within full-size pore-throat (Figure 11b). A smaller parameter value indicates better reservoir connectivity, making it easier for gas to enter pore-throat. However, as displacement pressure increases, more nanopore pore-throat become connected, weakening the influence of drainage pressure on P_og. Comparing P_og within pore-throats of different sizes post-displacement reveals that P_t is only negatively correlated with P_og within mesopores, with little correlation to the displacement results in other pore-throat sizes (Figure 12). This is because gas preferentially displaces fluid within mesopores' movable volume, whereas fluid displacement in micropores and nanopores is less (Figure 12). When dominant gas displacement pathways form within mesopores, gas accumulation within micropores and nanopores ceases to increase, minimizing the impact of P_t on gas distribution within these pore sizes.

Gas-occupied porosity (P_og) within full pore-throat sizes exhibits a weak negative correlation with the sorting coefficient (S_c) (Figure 11b). A smaller S_c indicates better pore-throat sorting performance, more uniform pore-throat size distribution, better connectivity, and overall improved gas displacement efficiency within the reservoir. This characteristic is similarly demonstrated in the homogeneity coefficient (H_c) of the reservoir, where a larger H_c favors better gas displacement of movable fluids within reservoir pore-throat. The correlation between P_og and these two parameters increases with pressure, indicating that better connectivity and homogeneity often yield better gas displacement effects with increasing displacement pressure, facilitating gas storage within the reservoir. The strong positive correlation between P_og and S_max and W_e validates this viewpoint (Figure 11b). Among different pore-throat sizes, the S_c and H_c primarily exhibit a strong correlation with P_og within micropores, as micropores constitute the main component of pore-throat at an average proportion of 51%. The higher the proportion of micropores, the smaller the selection coefficient, indicating better mineral selectivity, improved reservoir connectivity, and more favorable conditions for gas storage. Hydrodynamic stability and facies play a critical role in controlling the sorting characteristics of reservoirs. The Lm, deposited under unstable flow conditions at the margins of bars, exhibits significant grain size variation and poorly sorted pore-throat structures. In contrast, the Lmc, formed under more stable hydrodynamic conditions, displays improved sorting. Although Lm contains a higher proportion of mesopores, the overall gas-bearing performance of Lmc is more favorable.

5.1.4 Displacement pressure

Displacement pressure is another factor influencing the distribution characteristics of gas within the reservoir (Yang et al., 2022). Under the same pore-throat structure, a higher pressure leads to better displacement effectiveness and a more significant S_g. The P_og and the S_g within different pore-throat sizes under different displacement pressures can be seen in Figure 13. At the same pressure, gas is primarily distributed within mesopores, resulting in the best displacement effectiveness for movable volume. As the pore-throat size decreases, the P_og gradually decreases. This indicates that larger pore-throat radius and better pore-throat connectivity are conducive to enhancing gas displacement effectiveness and promoting gas storage within the reservoir after displacement (Figure 13a). Micropores and nanopores can also store some gas within the reservoir, but due to limitations in connectivity and pore-throat volume, only a tiny amount of movable volume is displaced by gas.

Figure 13

Figure 13. Box plots of gas-occupied porosity (P_og) (a) and gas saturation inside pore-throat (S_pt) (b) in different pore-throat sizes.

Comparing the displacement effects of pores-throat of the same size under different pressures reveals that the S_g within all size pore-throat categories gradually increases. Among them, the S_g of mesopores increases the fastest. However, as the pore size decreases, the displacement effectiveness gradually worsens (Figure 13b). The underlying difference causing this phenomenon lies in the varying pore-throat sizes, resulting in different reservoir connectivity and storage capacities. As the pore-throat size decreases, the pore-throat structure becomes more complex, connectivity deteriorates, and porosity rapidly decreases. Consequently, the ability of gas to penetrate pore-throat diminishes under the same displacement pressure, resulting in poorer displacement effectiveness.

The experimental results indicate that the gas accumulation in the tight sandstone of the J58 block exhibits a progressive characteristic. From the relationship between P_og, S_g, and displacement pressure (Figure 14), the gas charging process can be divided into two stages: a rapid growth stage and a slow growth stage. In the rapid growth stage, the charging pressure is generally less than 6 MPa, characterized by a rapid increase with rising charging pressure. For example, at 6 MPa, the gas-occupied porosity of Sample 6 in of Lpc (Type I) reached 4.57% (Figure 14a), and the corresponding cumulative gas saturation reached 31.4% (Figure 14b), accounting for 81% of the final gas saturation. Similarly, Sample 3 of Lmf (Type IV) achieved 83% of the final gas saturation. The slow growth stage is characterized by a relatively small increase in gas saturation with increasing displacement pressure. For instance, during the 6–10 MPa stage, the average increase in gas saturation for the four classes of samples was only 20%. In summary, when the pressure is below 6MPa, the gas saturation in tight sandstones can reach 80% of the total gas saturation. In the later stage, high-pressure gas charging primarily enters smaller pore-throats, leading to a slower increase in P_og and S_g. Therefore, the low-pressure charging during the rapid charging stage is key to achieving gas saturation. Under actual geological conditions, low-pressure displacement and larger reservoir pore-throat space can also form tight gas reservoirs with low gas saturation.

Figure 14

Figure 14. Relationship between P_og (a) and S_g (b) under different displacement pressure in tight sandstone.

5.2 Lithofacies controlled pore network model with gas and fluid mobility

Comparing the gas-bearing parameters under the final displacement pressure of different lithofacies, the Lpc exhibits the best fluid gas-bearing capacity, followed by the Lmc, with the Lm being less favorable and the Lmf having the poorest gas-bearing capacity (Figure 15). The depositional environment controls the lithofacies that form the reservoir, which in turn governs the pore-throat structure and ultimately affects the gas-bearing capacity of tight sandstone reservoirs. Therefore, a reliable depositional model is critical for analyzing gas distribution within reservoirs. This study establishes a gas distribution model for reservoirs in continental braided river environments based on pore-throat structure characteristics and controlling factors (Figure 16).

Figure 15

Figure 15. Box plots of the gas-occupied porosity (P_og) (a) and gas saturation (S_g) (b) for different sized pore-throat structures after the final water displaced gas pressure, including the 25th and 75th percentiles (short line), individual data points (circles), and the median (long line).

Figure 16

Figure 16. Pore network models of fluid distribution after water saturation and gas displacement in four lithofacies of fluvial braided river deposits. (a1–d1) CTS images of the four pore-throat types; (a2–d2) Distribution characteristics of gas and water within pore-throats after gas displaces water in different pore-throat structures; (a3) Pebbly coarse-grained sandstone; (b3) Medium to coarse grained sandstone; (c3) Medium sandstone; (d3) Medium to fine grained sandstone; (a4–d4) NMR T₂ spectrum showing changes in gas-water flow within the pore-throat structures for water saturation and gas displacement.

The Lpc is located at the base of superimposed distributary channel-fills with the largest grain size and sandstone thickness greater than 6 m. This lithofacies reflects a high-energy depositional environment and is characterized by high brittle mineral content, low clay mineral content, and moderately sorted pore-throat structures. It contains a high proportion of mesopores and micropores, primarily composed of residual intergranular pores (Figure 16). Sample 6 is representative of this lithofacies, showing excellent reservoir connectivity and the strongest fluid mobility. As a typical mesopore-dominated gas reservoir, Lpc represents a primary target for gas reservoir development, which explains its superior gas-bearing capacity. The Lmc was primarily deposited in the medial bars, with sandstone thickness of approximately 5 m. It exhibits good sorting and reflects a stable hydrodynamic environment. Although it has a relatively lower proportion of mesopores, the pore-throat is mainly composed of intergranular dissolution pores, with fewer intergranular pores. The relatively high micropore content and widespread distribution of Lmc indicate that it is also a favorable gas-bearing lithofacies, though slightly inferior to Lpc in gas-bearing capacity. The Lm was predominantly deposited at the edges of channel bars, with sandstone thickness of approximately 4 m. It has a high proportion of mesopores, but these are only locally developed, reflecting variable hydrodynamic conditions. Poor sorting and a high clay mineral content result in weaker reservoir connectivity. As such, while localized “sweet spots” within the Lm may serve as secondary development targets, its overall gas-bearing capacity is lower than that of Lpc and Lmc. The Lmf consists mainly of medium to fine grained sandstones deposited in levees adjacent to channel-fills, with sandstone thickness of less than 2 m. It has the lowest proportion of mesopores, the highest clay mineral content, and the poorest reservoir quality and pore-throat structure, leading to the lowest gas-bearing capacity among all lithofacies. Therefore, a comprehensive understanding of depositional models, particularly concerning variations in sandstone lithofacies and pore-throat structures, is critical for the development of tight sandstone gas reservoirs in continental braided river systems.

6 Conclusion

1. The four studied lithofacies, deposited by braided rivers, correspond to four pore-throat structure types. Pebbly coarse-grained sandstone (Lpc - Type I) has a coarse grain size, well-developed mesopores, and the best connectivity, which is conducive to gas seepage and is the best gas reservoir here; Medium to coarse grained sandstone (Lmc - Type II) has an increased proportion of micropores, but good connectivity, which is conducive to gas storage; Medium grained sandstone (Lm - Type III) has well-developed mesopores, but is limited by connectivity and clay content, and gas is mainly distributed in local pore-throat spaces; Medium to fine grained sandstone (Lmf - Type IV) has the worst pore-throat structure connectivity, mainly throats, and the worst reservoir gas content.

2. Each sample’s pore-throat size can be divided into nanopores (0.001–0.01 μm), micropores (0.01–0.1 μm), and mesopores (0.1–1 μm). Results indicate that mesopores are the primary gas storage space in the study area, with the highest gas-occupied porosity and displacement efficiency, followed by micropores, and nanopores exhibit the lowest occupancy.

3. Quartz is conducive to the preservation of mesopores and the storage of gas. High clay content will reduce reservoir connectivity, which is not conducive to gas displacement inside pore throats of different sizes. The physical properties of the reservoir mainly affect the gas content inside the mesopores. Rm, Sc and Hc can be used as important evaluation parameters for gas content of different pore-throat sizes.

4. Under the same displacement pressure, mesopores exhibit the highest displacement efficiency and are the primary targets for gas displacement. With increasing displacement pressure, all four types of samples experience two displacement stages: a rapid growth stage followed by a slow growth stage. At a displacement pressure of 6 MPa, gas saturation in all samples rapidly reaches approximately 80% of the final gas saturation, indicating that gas can preferentially invade the pore system and form continuous charging pathways under low charging pressure. Subsequently, gas mainly migrates into micropores and nanopores, causing the charging process to transition from a rapid to a slow stage. These results indicate that under low charging-driving conditions, the development of mesopores can partially compensate for insufficient charging pressure and promote gas migration and accumulation, enabling tight sandstones to form effective gas reservoirs even under relatively low charging pressures. This provides important implications for the exploration and evaluation of low-pressure charged tight gas reservoirs.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

Author contributions

LB: Methodology, Writing – original draft, Conceptualization, Data curation, Formal Analysis, Validation. QC: Data curation, Formal Analysis, Investigation, Methodology, Software, Writing – original draft. YL: Resources, Supervision, Visualization, Writing – review and editing. JH: Funding acquisition, Methodology, Software, Supervision, Writing – review and editing. ZZ: Resources, Visualization, Writing – review and editing.

Funding

The author(s) declared that financial support was received for this work and/or its publication. This work was supported by the National Natural Science Foundation of China (Nos. 42172154 and 42472205).

Acknowledgements

We appreciate the geologists from the North China Petroleum Bureau, SINOPEC for data support. Also, the authors would like to express their gratitude for the academic support provided by Prof. Nigel P. Mountney and Dr. Adam McArthur, University of Leeds in the completion of this research paper.

Conflict of interest

Author ZZ was employed by SINOPEC North China Company.

The remaining author(s) declared that this work was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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