The pore-throat structure is a critical factor in the study of unconventional oil and gas reservoirs, drawing particular attention from petroleum geologists, and it is of paramount significance to analyze to enhance oil and gas production. In tight sandstone, which serves as a significant hydrocarbon reservoir, the internal pore-throat structure plays a decisive role in the storage and migration of fluids such as water, gases, and hydrocarbons. This paper employs casting thin section (CTS), field emission scanning electron microscope (FE-SEM), high-pressure mercury injection (HPMI), and low-temperature nitrogen gas adsorption (LT−N₂−GA) experimental tests to qualitatively and quantitatively analyze the characteristics of the pore-throat structure in tight sandstone. The results indicate that the pore types in tight sandstone include intergranular residual pores, dissolution pores, intercrystalline pores, and microfractures, while the throat types encompass sheet-shaped, curved-sheet-shaped, and tubular throats. Analysis of the physical and structural parameters from 13 HPMI and 5 LT−N₂−GA samples reveals a bimodal distribution of pore-throat radii. The complexity of the pore-throat structure is identified as a primary controlling factor for reservoir permeability. The fractal dimension (D) exhibits an average value of 2.45, displaying a negative correlation with porosity (R² = 0.22), permeability (R² = 0.65), the pore-throat diameter (R² = 0.58), and maximum mercury saturation (R² = 0.86) and a positive correlation with threshold pressure (R² = 0.56), median saturation pressure (R² = 0.49), BET specific surface area (R² = 0.51), and BJH total pore volume (R² = 0.14). As D increases, reservoir pores tend to decrease in size, leading to reduced flow and deteriorated physical properties, indicative of a more complex pore-throat structure.

In recent years, tight sandstone oil and gas have been an important area for unconventional oil and gas exploration and development in China. It is of great significance to clarify the pore-throat structure characteristics of tight sandstone reservoirs to guide production practices. This study takes the tight sandstone of the sixth member of the Yanchang Formation in the Huaqing area, Ordos Basin, as an example, based on experimental methods such as high-pressure mercury intrusion, cast thin sections and scanning electron microscopy. At the same time, the pore-throat structure of tight sandstone reservoirs is divided into three types using the tube-bundle and spherical fractal models. The corresponding pore and throat radius distribution, pore-throat combination mode and influencing factors of various pore-throats are studied. The results show that the fractal dimension of type I pore-throats is the smallest, and the distribution of their pore-throat radii is the most uniform. They are dominated by intercrystalline pores and dissolution pores with tube-bundle throats and small pores with small throats. Type II pore-throats have the largest fractal dimension and the worst pore-throat uniformity. They are dominated by residual primary intergranular pores with necked throats and large pores with small throats. The type III pore-throat fractal dimension is in the middle, mainly composed of residual dissolved intergranular pores with pore-reduced throats, sheet-like and curved sheet-like throats, and large pores with large throats. The influence of different pore-throat combinations on the reservoir is reflected in the different characteristics of mercury injection parameters. The main influencing factors for the differences in the fractal dimensions of different pore-throats are diagenesis, rock composition and pore-throat combination type. Diagenesis and rock composition, in turn, affect the type and development degree of pore-throats, as well as the combination of pore-throats. The purpose of this study was to clarify the internal connection modes of different homogeneous pore-throats and their influencing factors, enrich the theoretical basis for the study of tight sandstone reservoirs and provide theoretical guidance for their exploration and development.

The Ordovician carbonate succession in the western Ordos Basin, China, represents an important target for unconventional hydrocarbon exploration, particularly shale gas in the Wulalike Formation. In this study, we utilize high-resolution elemental logging data from MJ1 well to reconstruct the paleoenvironmental evolution of the basin and evaluate the controlling factors on organic matter enrichment. Major and trace element distributions reveal distinct geochemical signatures across stratigraphic units, reflecting variations in lithology, productivity, redox conditions, paleoclimate, salinity, and water depth. Proxies such as Al/Ti, Cu/Al, U/Th, Sr/Cu, and Rb/K were applied to infer paleo-productivity, redox state, climate, and bathymetric trends. The results indicate that the Wulalike Formation experienced relatively high paleoproductivity, dysoxic to suboxic redox conditions, semi-arid climate, and moderate water depth, creating favorable conditions for organic matter accumulation. A progressive transgressive sequence is documented from the Sandaokan to Wulalike Formations, with corresponding shifts in facies and geochemical environments. These findings provide new insights into the depositional evolution and hydrocarbon potential of the Ordovician strata in the western Ordos Basin and offer valuable implications for future shale gas exploration strategies.

To clarify the hydrocarbon-generation potential of deep source rocks in the Qingyang Gas Field, this study focuses on the Shanxi and Taiyuan Formation source rocks at burial depths of 4000–5000 m. Integrated organic geochemical analyses were conducted to investigate organic matter abundance, kerogen type, thermal maturity, hydrocarbon-generation conditions, and their significance for natural gas accumulation. The TOC values of the 12 valid mudstone samples range from 0.07% to 2.53%, with an average of 0.77%, indicating generally poor to fair organic matter abundance. Rock-Eval results show that S2 values range from 0.0681 to 6.2797 mg/g, with an average of 1.5946 mg/g, whereas S1 + S2 values range from 0.0948 to 6.9066 mg/g, with an average of 1.8582 mg/g, indicating generally limited Rock-Eval hydrocarbon-generating capacity, with local improvement. The kerogen assemblage is heterogeneous and is generally dominated by Type III humic kerogen, with subordinate Type II components and minor Type I components in some samples, indicating mixed organic-matter input but an overall gas-prone character. Tmax values range from 420 to 482 °C; however, because Tmax may be unreliable in samples with very low S2 values, thermal maturity was evaluated mainly using vitrinite reflectance and natural gas geochemical evidence. R_o values range from 2.03% to 2.22%, with an average of 2.11%, indicating that the source rocks have reached a high- to overmature stage. The natural gas is methane-rich, with an average methane content of 91.73% and an average heavy hydrocarbon content of only 0.16%, indicating a typical dry-gas composition. The carbon isotope values of methane and ethane are both negative, with δ¹³C₁ values ranging from −35.59‰ to −20.65‰ and δ¹³C₂ values ranging from −37.82‰ to −28.44‰, consistent with high-maturity coal-derived gas generated from humic organic matter. The formation water is mainly medium- to high-salinity CaCl₂ type, indicating a relatively closed hydrologic environment favorable for natural gas preservation. Clay mineral assemblages dominated by kaolinite and illite provide supplementary evidence for depositional conditions, burial diagenesis, and fluid–rock interaction. Overall, although the Rock-Eval hydrocarbon-generating capacity of the Shanxi and Taiyuan Formation source rocks is generally limited, the Type III-dominated mixed kerogen, high- to overmature R_o values, methane-rich dry-gas composition, and carbon isotope characteristics collectively indicate that these source rocks experienced effective natural gas generation during geological evolution and are genetically related to the present deep natural gas accumulation. This study provides fundamental geochemical constraints for further integrated exploration and evaluation of the deep coal-measure gas system in the Qingyang Gas Field.