On the basis of the observation of rock cores and cuttings, combining the information from thin section identification, physical properties analysis, scanning electron microscopy, X-ray diffraction, etc., the characteristics and controlling factors of the tight reservoir in the Permian Lucaogou Formation of the Yongfeng sub-sag of the Chaiwopu sag have been studied. Based on the analysis, the Lucaogou Formation in the study area can be divided into two lithological sections. The tight sandstone reservoir, characterized by low porosity and low permeability, is mainly developed in the upper section of the Lucaogou Formation. The lithology of the tight reservoirs is mainly lithic sandstone with low compositional and structural maturity. The reservoir space types mainly consist of secondary pores, including intergranular dissolution pores, intragranular dissolution pores and fractures, and the primary pores are severely destroyed. The main controlling factors of reservoirs include sedimentary facies, lithology, diagenesis, later tectonic movements and fractures, and the latter two factors have a significant impact on improving reservoir physical properties and seepage capacity. The tight reservoir has high brittleness and low water sensitivity, which is very conducive to large-scale hydraulic fracturing to transform the reservoir and improve oil and gas production capacity.

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ¹³C₂ of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ¹³C₁ of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II₁. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

The Early Carboniferous Dawuba Formation within the Yadu-Ziyun-Luodian aulacogen (YZLA), southern China, represents a significant shale gas play formed within a dynamic platform-basin transitional sedimentary system influenced by multi-sphere coupling (the dynamic interaction of tectonic, climatic, and oceanic spheres). This setting generated pronounced heterogeneities in lithology and gas content. Integrating field geological surveys and well data, this study comprehensively evaluates the mineralogy, geochemistry, structural features, and gas content of these shales to decipher the key factors controlling gas enrichment, particularly in this tectonically complex area. A crucial finding is the distinction between low-energy, “thick-bedded” deposits and higher-energy, “thin interbedded” sections characterized by frequent alternations of mudstone and argillaceous limestone (0.5–5 m single layers, mudstone:limestone ratio 1:1–1:2). Significantly, these thin interbedded sections demonstrate superior reservoir quality, exhibiting higher porosity (∼2.9%) and notably higher gas content (∼2.5 m³/t). We reveal that in the YZLA’s complex structural setting, shale gas content is primarily governed by preservation conditions dictated by the unique litho-mechanical properties of the interbedded strata, rather than traditional controlling factors like TOC abundance or matrix porosity. The frequent interlayering promotes stable micro-fractures, supported by clay-rich horizons and effectively sealed by compact limestone, thereby enhancing secondary storage capacity and permeability for free gas. Consequently, these thin interbedded sections represent the most favorable intervals for shale gas accumulation, identifying them as the prime targets for achieving Early Carboniferous shale gas breakthroughs in the YZLA.

The exploration level of the Bogda Mountain front belt is relatively low, and the research on hydrocarbon accumulation is limited, resulting in unclear sources of discovered oil. To further investigate the geochemical characteristics and sources of crude oil in the Bogda Mountain front belt, this study conducted geochemical experimental analysis and oil–source correlations on crude oil and hydrocarbon source rock samples from the Permian Lucaogou Formation in the Yongfeng sub-sag and surrounding areas of the Bogda Mountain front belt. By using gas chromatography–mass spectrometry technology, the geochemical characteristics of saturated hydrocarbons and aromatic compounds were analyzed. Combined with stable carbon isotopes of saturated hydrocarbons and aromatic hydrocarbons, the organic matter source, maturity, and sedimentary environment were determined. The research results indicate that the crude oil from Well Xyd 1 exhibits mature characteristics, and the source material was deposited in a reducing to weakly oxidizing, weakly reducing environment. The source rocks of the Lucaogou Formation in Well Xyd 1 were formed in a reducing, semi-saline–saline sedimentary environment, while those from the Gjg and Dhs outcrops developed in a weakly oxidizing–weakly reducing, non-high-salinity, weakly stratified sedimentary environment. Carbon isotope, terpane, and isoalkane characteristics confirm a significant genetic relationship between the crude oil from Well Xyd 1 and the local Luzhaogou Formation source rocks. The source rocks of the Luzhaogou Formation in the Yongfeng sub-sag exhibit strong heterogeneity, with significant differences in sedimentary environments and parent materials in their spatial distribution. Maturity analysis indicates that the Luzhaogou Formation source rocks in Well Xyd 1 have reached a mature stage, whereas those from the Gjg and Dhs outcrops are at a relatively low maturity level.

The Ulungu Depression, located in the northeastern Junggar Basin, adjacent to the Altai Orogenic Belt, exhibits distinctive tectonic relationships and evolutionary mechanisms. Through integrated interpretation of seismic and electromagnetic data, a composite transect was established to characterize the deep-to-shallow geological architecture of the Altai Orogenic Belt–Ulungu Depression system. The tectonic evolution since the Late Paleozoic was reconstructed, revealing three distinct phases: (1) Late Paleozoic peripheral foreland basin development, (2) Mesozoic intracontinental foreland basin formation, and (3) Cenozoic intracontinental foreland basin reactivation. The Late Paleozoic phase records the formation of a peripheral foreland basin in the northeastern Junggar Basin, driven by the Altai-Junggar collision orogeny. During the Mesozoic, intracontinental orogeny along the Altai Belt controlled the development of an intracontinental foreland basin in this region. Paleogene tectonic quiescence facilitated regional subsidence and stable sedimentary deposition. From the Neogene to Quaternary, the Ulungu Depression experienced weak compressional deformation dominated by minor thrust faults, with intermittent regional extensional structures, attributable to the far-field effects of the India-Eurasia collision. This distant tectonic stress primarily localized intracontinental orogeny in the North Tianshan, while the Ulungu Depression, situated farther north, exhibited attenuated strain partitioning. Reconstruction of this multi-phase tectonic evolution provides critical insights into the accretionary orogenic processes of Central Asia. Furthermore, it offers practical implications for hydrocarbon exploration in the Ulungu Depression, particularly regarding structural traps and reservoir distribution patterns.

This study is based on field observations and sample collections from the Panjinbulak, Qiongbulak, and Qunjisayi outcrops in the Yining Sag of the Ili Basin. Using organic geochemical analysis methods, the characteristics and hydrocarbon generation potential of the Permian Xiaoshansayi Formation (P₂x) and Tamqisayi Formation (P₂t) source rocks in the Yining Sag were compared and analyzed. The results indicate that the Permian source rocks in the Yining Sag of the Ili Basin exhibit high organic matter abundance and good types, among which the P₂t source rocks are overall superior to the P₂x. The P₂t source rocks in the Panjinbulak outcrop section on the northern margin are dominated by Type II₁-II₂ kerogen, while those in the Qunjisayi and Qiongbulak outcrop sections on the southern margin show a transition to Type II₂-III kerogen. The maturity of Permian source rocks presents a pattern of “higher in the south and lower in the north”, and all have reached the hydrocarbon-generation threshold. The northern margin is in the oil window, mainly dominated by oil generation; the southeastern margin has higher maturity, mainly producing oil/condensate gas. The Permian source rocks were deposited in a saline-reducing environment, with mixed input of aquatic organisms and terrestrial plants. During the deposition of P₂t source rocks in the northern margin, the water salinity was higher, and plankton such as cyanobacteria made prominent contributions. The P₂t source rocks in the Panjinbulak outcrop section on the northern margin have relatively better organic matter abundance and type, making it the main hydrocarbon-generation-potential area. The source rocks in the Qunjisayi outcrop section on the southeastern margin are slightly poorer, but their maturity is higher, currently in the main oil window, representing a secondary hydrocarbon-generation-potential area.