Search Results (32)

Deep lacustrine rift basins present persistent challenges in hydrocarbon provenance determination, charging-history reconstruction, and migration pathway prediction within heterogeneous deep reservoirs. This study applies an integrated approach combining biomarker and light-hydrocarbon geochemistry, fluid-inclusion microthermometry, and two-dimensional migration modelling to the deep Eocene Dainan Formation in the southeastern Gaoyou Sag, Subei Basin. Based on 20 analytical entries from Dainan oils/reservoir samples and Funing Formation source-rock extracts, the results indicate mixed contributions from the E₁f₂ and E₁f₄ source intervals rather than a single-source origin. Maturity parameters place most oils within the early- to main-oil window, while hydrocarbon inclusions with dominantly blue fluorescence and homogenization temperatures of 85–110 °C are consistent with a dominant Sanduo-period charging episode. Integrated migration modelling identifies two accumulation styles: a northern fault-slope migration system and a southern Zhenwu fault-conduit system, with effective accumulation favoured by the coupling of active faults and connected sand bodies. The established genetic model offers a transferable framework for derisking exploration in analogous deep lacustrine rift basins. Full article

Marginal lacustrine systems are highly sensitive archives of hydrological fluctuations, climatic variability, and changes in sediment supply in continental basins. The Alagöz Formation (Late Miocene–Pliocene) exposed in the Haymana–Polatlı Basin, Central Anatolia, was investigated through integrated sedimentological, mineralogical, geochemical, and stable isotope analyses to constrain provenance, weathering history, and lacustrine hydrological variability. Facies analysis reveals a transition from alluvial–fluvial systems to a shallow marginal lacustrine environment subjected to short-term hydrological fluctuations. Mineralogical and geochemical data indicate that sedimentation occurred within a mixed carbonate–siliciclastic lacustrine system controlled by variable lake-water chemistry. Detrital mineral assemblages indicate contributions from metamorphic source rocks. Trace-element and REE signatures suggest derivation mainly from felsic-to-intermediate continental sources. Reworked carbonate fragments and fossil debris indicate recycling of older carbonate units. The occurrence of calcite, dolomite, and protodolomite reflects variable Mg/Ca ratios, whereas clay mineral assemblages record shifts between detrital input during relatively humid phases and chemically concentrated conditions. Palygorskite occurrence indicates localized and episodic alkaline conditions associated with short-lived evaporative concentration. Weathering indices (CIA, CIW, PIA, and ICV) suggest low-to-moderate chemical weathering and compositionally immature sediments, consistent with transitional humid to semi-arid climatic conditions. Trace-element systematics also indicate a minor mafic contribution to the detrital source. Stable isotope values (δ¹³C: −7.05‰ to +2.82‰; δ¹⁸O: −8.60‰ to −2.94‰ VPDB) and their weak correlation (r = 0.34) support a shallow, hydrologically dynamic lacustrine system dominated by freshwater input but episodically influenced by evaporative concentration. Taken together, the Alagöz Formation records a sensitive marginal lacustrine system shaped by short-term hydrological fluctuations. These findings provide a useful analog for understanding hydrologically sensitive marginal lacustrine systems developed in post-collisional continental basins under fluctuating semi-arid climatic conditions. Full article

Typical saline lacustrine mixed sedimentary strata are developed in the Middle Permian Lucaogou Formation (P₂l) in the Jimsar Sag, with frequent interbedding of mudstone, dolomitic mudstone, and argillaceous dolomite. The widespread development of dolomite is a key factor controlling the quality of shale oil reservoirs. To reveal the formation mechanism of dolomite in mixed sedimentary rocks and its constraint on lithological assemblages, this study focuses on comparing the differences in mineralogy, geochemistry, and sedimentary environment of the three types of lithologies based on systematic tests such as thin-section observation, X-ray diffraction, major and trace element analysis, organic petrology, and biomarker analysis. The results indicate that dolomite formation in the study area is not controlled by a single factor, but instead results from the combined control of hydrothermal activity, microbial metabolism, and paleoclimatic fluctuations. Hydrothermal activity provided a source of Mg²⁺, and together with evaporation driven by an arid climate, elevated the Mg/Ca ratio of the lake water, establishing the hydrochemical basis favorable for dolomite development. Metabolic activities of lower aquatic organisms, such as bacteria and algae, promoted the formation of a sustained alkaline environment, creating favorable conditions for dolomite precipitation. Against a background of a relatively arid climate, the alternation of extreme arid and extreme precipitation events caused frequent fluctuations in lake water saturation, potentially providing ideal dynamic conditions for rapid and abundant dolomite formation. This combined control governed dolomite development and produced the interbedded lithological succession in the P₂l mixed sedimentary strata. This study integrates the dominant controlling factors and synergistic mechanisms of dolomite development in mixed sedimentary strata of continental saline lacustrine basins, which helps predict the occurrence and distribution of high-quality reservoir lithologies within such strata and has important implications for the optimization of “sweet spots” in shale oil exploration. Full article

This study aims to resolve the genetic origin of crude oils accumulated in the D Subsag and to assess the potential cross-sag hydrocarbon migration from the adjacent Haizhong Sag. The D Subsag, situated on the western margin of the Weixinan Sag in the Beibuwan Basin, is a significant petroleum province with proven reserves exceeding 10 million tons in the Weizhou Oilfield. However, the origin of these oils and the contribution from the Haizhong Sag source kitchen remain poorly constrained, hindering accurate resource assessment. To address this, we integrated organic geochemical analyses of nine source rock samples from the Haizhong Sag (Well H1) and eight crude oil samples from the D Subsag reservoirs. Bulk geochemical and biomarker signatures reveal distinct organic facies within the Paleogene succession. Type III kerogen, characterized by terrigenous higher plant input (high C₁₉₊₂₀ tricyclic terpanes and C₂₉ regular steranes, Pr/Ph > 2.5) deposited under oxic freshwater conditions, dominates source rocks from the third member of the Weizhou Formation (EWZ₃). In contrast, the second and third members of the Liushagang Formation (Els₂ and Els₃) contain mixed Type II₂-III kerogen with elevated contributions from lacustrine algae and aquatic organisms (elevated C₂₃ tricyclic terpanes and C₂₇ regular steranes). Thermal maturity assessment (with T_max of 436 to 448 °C) confirms that all source intervals are within the oil generation window. Two genetically distinct oil groups are identified in the EWZ₃ reservoirs. Group 1 oils (Well W4) exhibit a lacustrine algal signature (C₂₇/C₂₉ sterane > 1.15; low Pr/Ph 1.54–1.68) that does not correlate with the analyzed Haizhong Sag source rocks, suggesting localized, intra-sag source contributions. In contrast, Group 2 oils (Wells W6 and W6-2) display strong geochemical affinities with the Els₂ and Els₃ source rocks, evidenced by mixed terrestrial/aquatic signatures (∑nC₂₁⁻/∑nC₂₂⁺ < 1.0). These findings confirm that fault systems acted as conduits for long-distance migration from the Haizhong Sag, while also highlighting a previously unrecognized contribution from local source intervals. This refined petroleum system model provides critical constraints for delineating remaining hydrocarbon potential and reducing exploration risk in the Beibuwan Basin. Full article

Early Jurassic organic-rich shales deposited in fluvio-deltaic settings serve as important hydrocarbon source rocks, particularly in the highly petroliferous basins of the Middle East. The Lower to Middle Jurassic sedimentary succession of the frontier Kohat Basin, Pakistan, comprises thick sequences of shale, coaly, and carbonate rocks deposited along the northwestern margin of the Indian Plate, adjacent to the eastern Tethys Ocean, and records a crucial paleoenvironmental transition from fluvio-deltaic to shallow marine settings. Despite the economic significance of the Jurassic succession as a potential hydrocarbon source in the Kohat Basin and surrounding regions, their organic geochemical characteristics and role in the regional petroleum system remain poorly understood. This study presents an integrated organic geochemical and carbon isotopic evaluation of Jurassic source rocks using well cuttings and outcrop samples, focusing on organic matter (OM) input, depositional environment, hydrocarbon generation potential, thermal maturity, and oil–source rock correlation. Source rock characterization indicates that the Shinawari and Datta formations possess fair-to-excellent generative potential, whereas the Samana Suk Formation exhibits poor-to-marginal potential. Biomarker and isotopic evidence indicate that the Shinawari Formation is dominated by algal-derived OM, characterized by higher aquatic OM deposited under relatively reducing marine to marginal marine conditions. The relatively more depleted bulk and individual fraction δ¹³C values for the Shinwari Formation are also consistent with a stronger marine influence. In contrast, the Datta Formation shows mixed OM inputs with a greater terrestrial influence and suggests deposition in more oxic lacustrine to marginal marine settings. The thermal maturity-related parameters for both formations indicate early to peak oil window thermal maturity. The geochemical correlation of Jurassic source rock extracts with Kohat crude oils, based on published data, suggests that the Kohat oils differ significantly, exhibiting stronger terrestrial organic matter signatures, more oxic depositional conditions, and slightly higher maturity, thereby indicating no direct genetic linkage with the Jurassic source rocks. Overall, the Jurassic formations are unlikely to represent the primary source rocks for Kohat oils but may have contributed locally to a multi-source petroleum system. This underscores the need for integrated geochemical investigations combining biomarker and isotopic analyses, supported by broader source rock and crude oil datasets, to resolve uncertainties in oil–source correlations, source contributions, and hydrocarbon migration pathways, thereby better constraining the petroleum system framework. Full article

Reservoir quality in shallow lacustrine-mixed siliciclastic–carbonate systems is commonly governed by mineral assemblages and diagenetic modification. Here we investigate the Neogene Youshashan Formation (Oil Groups III–V) in the Nanyishan area, western Qaidam Basin, to quantify mineralogical and diagenetic controls on pore systems and flow. We integrate whole-rock XRD and log-derived mineral profiles with thin-section/SEM petrography, NMR T2 spectra, mercury injection capillary pressure (MICP), and a water-drop test. Dissolution-related pores and dolomitization-related intercrystalline pores dominate the pore space, whereas cementation and clay-related filling/coating locally restrict pore throats and connectivity. Algal limestones (average porosity 23.17% and permeability 54.3 mD; MICP r50 = 0.085 μm) show better reservoir quality than dolomitic rocks (average porosity 17.24% and permeability 15.13 mD; MICP r50 = 0.039 μm), consistent with more effective pore throat networks. In Oil Group III (Well NQ2-6-2), higher dolomite content is generally associated with higher porosity but shows no systematic relationship with permeability, highlighting the primacy of connected pore throats. Water-drop behaviors (beading, semi-beading, infiltration) provide a rapid, semi-quantitative screening indicator when interpreted together with pore throat metrics, and support a four-class reservoir-typing scheme (Types I–III and non-reservoir) for sweet-spot identification in mixed lacustrine reservoirs. Full article

The second member of the Kongdian Formation (Ek₂; also referred to as the Kong 2 Member) in the Cangdong Sag within the Bohai Bay Basin contains a series of high-quality lacustrine shales characterized by high organic matter abundance and significant hydrocarbon shows. However, the mechanisms governing organic matter enrichment in the deep parts of the sag remain poorly understood, and the impacts of depositional environments on organic matter enrichment are yet to be determined. This study investigated shales in the C1, C3, and C5 sublayers of the Kong 2 Member. Specifically, this study examined the mineralogy and petrology, organic geochemistry, and elemental geochemistry of the shales using whole-rock X-ray diffraction (XRD) analysis, total organic carbon (TOC) analysis, pyrolysis experiments, and analyses of macerals, major and trace elements, and stable carbon and oxygen isotopes. Additionally, numerical analyses were conducted. The results indicate that shales in the Kong 2 Member consist primarily of felsic, dolomitic–calcareous, and mixed shales. These shales exhibit high TOC content (average: 3.07%), and favorable organic matter types dominated by liptinite and interbedded with minor planktonic algae and amorphous sapropelinite. These suggest great potential for hydrocarbon exploitation. During the deposition of shales in the Kong 2 Member, substantial terrigenous clasts were deposited at moderate rates under relatively arid climates characterized by frequently alternating dry and humid conditions. In this period, the anoxic to reducing depositional water bodies showed elevated salinity, resulting in saline-to-brackish water environments and moderate paleoproductivity. The organic matter enrichment of shales in the Kong 2 Member was jointly governed by paleoclimate dynamics, terrigenous input, and redox conditions, as demonstrated by multivariate analyses including the correlation analysis of depositional environmental factors, the univariate analysis of TOC content, gray relational analysis (GRA), and robust regression analysis. Two organic matter enrichment patterns were identified: (1) the preservation-dominated pattern under arid climates, governed by intense reducing environments, and (2) the productivity-driven pattern under humid climates, enhanced by terrestrial input. Full article

This study systematically investigates the lithofacies, sedimentary microfacies, vertical evolution, and spatial distribution of the braided river delta–shallow lacustrine carbonate mixed sedimentary rocks of the Upper Ganchaigou Formation in the Huatugou Oilfield of the Qaidam Basin, China. This study integrates data from field outcrops, core observations, thin section petrography, laboratory analyses, and well-logging interpretations. Based on these datasets, the sedimentary characteristics are identified, and a comprehensive sedimentary model is constructed. The results reveal that the study area contains five clastic facies, three types of mixed sedimentary facies, and ten sedimentary microfacies. Two distinct modes of mixed sedimentation are recognized: component mixing and stratigraphic mixing. A full lacustrine transgression–regression cycle is formed by the two types of mixed sedimentation characteristics, which exhibit noticeable differences in vertical evolution. Component mixing, which occurs in a mixed environment of continuous clastic supply and carbonate precipitation during the transgression, is the primary characteristic of the VIII–X oil formation. The mixed strata that make up the VI–VII oil formation show rhythmic interbedding of carbonate and clastic rocks. During the lacustrine regression, it shows the alternating sedimentary environment regulated by frequent variations in lacustrine levels. The planar distribution is affected by both intensity of sediment from the west and the changes in lacustrine level. During the lacustrine transgression, it is dominated by littoral-shallow lacustrine mixed beach bar and mixed sedimentary delta. On the other hand, during the lacustrine regression, it is dominated by laterally amalgamated sand bodies in the braided-river delta front. Based on this, a mixed sedimentary evolution model controlled by the coupling of “source–lacustrine level” is established. It offers a guide for reconstructing the sedimentary environment in basins that are similar to it and reveals the evolution path of mixed sedimentation in the short-axis source area of arid saline lacustrine basins. Full article

This study investigates the Lower Cretaceous Madongshan Formation in the Liupanshan Basin, a classic saline lacustrine succession, to elucidate the key mechanisms for high-quality source rock development. An integrated approach combining organic geochemistry (Rock-Eval, Gas Chromatography–Mass Spectrometry [GC-MS], δ¹³C) and inorganic elemental geochemistry (X-ray Fluorescence [XRF]) was applied to a well-characterized outcrop section. The results reveal that the Madongshan Formation contains mature, oil-prone source rocks dominated by Type II₁ and II₂ kerogen. Geochemical proxies consistently indicate deposition within an arid to semi-arid climate, which drove the formation of a stratified, saline-to-hypersaline water column with persistent bottom-water anoxia (Pristane/Phytane [Pr/Ph] < 0.5). Isotopic and biomarker data confirm a mixed source input, with an average contribution of approximately 55% from aquatic organisms supplemented by a significant terrestrial influx. Based on these findings, we propose a “Salinity-Driven Preservation” model. This model posits that climate-induced salinity played a critical role in establishing a persistent halocline, leading to an intensely anoxic “preservation factory” at the lake bottom. Current evidence suggests that this exceptional preservation efficiency was a pivotal factor compensating for moderate productivity to control organic matter enrichment. This study provides a robust framework for predicting source rock quality in the Liupanshan Basin and serves as a valuable analogue for other saline lacustrine systems. Full article

The Dixi area of the Junggar Basin has favorable petroleum geological conditions, with the Cretaceous system representing one of the principal hydrocarbon-bearing strata. However, the genetic origin and mixing characteristics of natural gas across different tectonic zones remain insufficiently understood. In this study, a total of 65 natural gas samples were analyzed using molecular composition and stable carbon isotopic data to determine gas origins and quantify the contributions of different source rocks. A novel multivariate mathematical analysis method was developed and applied to convert compositional and isotopic data into quantitative parameters, enabling the accurate estimation of end-member mixing ratios in natural gas. This methodological innovation addresses the challenge of interpreting multi-source gas systems under complex geological conditions. The results show that the Cretaceous natural gas in the Dixi area is derived from three main sources, comprising both oil-type gas from Permian lacustrine source rocks and coal-type gas from Carboniferous coal-measure source rocks. The calculated mixing proportions exhibit significant spatial variation: in the northern Dixi area, coal-type gas dominates (67.8–84.3%), while the southern zone presents a broader mixture (25.6–68.4% coal-type gas). In the Dongdaohaizi Depression, oil-type gas is predominant, accounting for 89.4–97.7%. This study not only clarifies the genetic classification and mixing dynamics of natural gas in the Dixi area but also provides a quantitative framework for evaluating accumulation processes and source contributions in multi-source gas reservoirs. The proposed method offers valuable guidance for assessing resources and optimizing exploration strategies in the Junggar Basin and other similar basins. Full article

The occurrence of gypsum in clastic rocks of continental saline lake basins reflects complex depositional and diagenetic processes. However, its genesis remains relatively understudied. Based on core descriptions and thin-section analyses, this study investigates the occurrence types and genetic mechanisms of gypsum in the Bottom Sandstone Member of the northern Tabei Uplift. Five types of gypsum occurrences are identified: layered gypsum, gypsum clasts, spotted gypsum, gypsum nodules, and a mixed deposition of clastic rocks and gypsum. The mixed deposition of clastic rocks and gypsum includes gypsiferous mudstone, muddy gypsum, gypsiferous mudstone containing muddy clasts, and sandy gypsum. Layered gypsum, spotted gypsum, gypsiferous mudstone, and muddy gypsum mainly result from in situ chemical precipitation during periods of high evaporation and reduced runoff. In contrast, gypsum clasts, gypsiferous mudstone containing muddy clasts, and sandy gypsum reflect processes of transportation and reworking induced by flood events. Seasonal variations in hydrodynamic conditions play a critical role in the formation and distribution of gypsum. During dry periods, surface runoff weakens or ceases, and the salinity of lake water or pore water in clastic deposits increases due to intense evaporation, promoting gypsum precipitation. During flood periods, increased runoff can erode previously formed gypsum, which is subsequently transported and deposited as gypsum clasts. The morphology of gypsum varies with its transport distance. These findings enhance our understanding of clastic–evaporite mixed systems in arid continental lacustrine settings and provide insights into sedimentary processes influenced by seasonal climatic fluctuations. Full article

The exploration of the Fengcheng Formation has revealed the characteristic orderly coexistence of conventional reservoirs, tight reservoirs, and shale reservoirs, constituting a full spectrum of reservoir types, and is important for unconventional oil and gas exploration and development. Affected by frequent volcanic tectonic movement, hot and dry paleoclimate, and the close provenance supply distance, unique saline–alkaline lacustrine deposits formed during the depositional period of the Fengcheng Formation. The lithologies of the Fengcheng Formation are highly diverse, with endogenous rocks, volcanic rocks, terrigenous debris, and mixed rocks overlapping and forming vertical reservoir changes ranging from meters to centimeters. Owing to the complexity of rock types and scarcity of rock samples, the evaluation of reservoirs in mixed-rock has progressed slowly. Hence, we aimed to evaluate the characteristics of Fengcheng Formation shale oil reservoirs. Centimeter-level core characteristics were analyzed based on the lithological change and structural characteristics. To investigate the lithofacies of the Fengcheng Formation in the Mahu Sag and factors affecting reservoir development, high-frequency sedimentary structures were analyzed using sub-bio-buffering electron microscopy, energy spectrum testing, and fluorescence analysis. The results showed that the shale oil reservoirs in the study area can be divided into four categories: glutenite, volcanic rock, mixed rock, and endogenous rock. The reservoir capacity has improved and can be divided into eight subcategories. Mixed-rock reservoirs can be further divided into four subcategories based on differences in structure and composition. Differences in the bedding and dolomite content are the main factors controlling the differences in the physical properties of this type of reservoir. This study provides a reference for the classification and characteristic study of shale oil reservoirs in saline–alkali lake basins. Full article

The Dibei Gas Field, located in the northern Kuqa Foreland Basin, Tarim Basin, western China, is one of the most important condensate gas-producing areas in China, with over one trillion cubic feet of gas reserves discovered in the Jurassic terrestrial reservoirs. However, further hydrocarbon exploration and development in the area is hampered by uncertainties on the petroleum sources. A robust oil–source and gas-source correlation analysis was carried out in the Dibei area to enhance our understanding of the gas accumulation potential. An integrated molecular geochemical analysis, multivariate analysis, and basin modeling were conducted to investigate source rocks, inclusion oils, reservoir oils, and gas from the Dibei area. Two types of source rocks have been identified in the Dibei area: a Jurassic coaly source rock and a Triassic lacustrine source rock based on multivariate analysis. The compositions of the n-alkanes, steranes, and terpanes and the carbon isotope ratios of individual n-alkanes in the inclusion oil extracts and reservoir oils from Jurassic Yangxia and Ahe reservoirs show distinct differences when compared with the two types of source extracts. Multiple oil sources are revealed in the Dibei area, with various degrees of mixing between reservoir oil (present) and inclusion oil (paleo), reflecting evolving oil sources. Basin modeling shows that during the late Himalayan orogeny, the Jurassic strata in the Dibei area experienced a rapid burial within ~20 Ma, with the oil generation window of the source rocks expanding greatly. This caused the shallowly buried Jurassic source rocks to enter the oil generation window, resulting in the occurrence of two oil sources for the inclusion oils and reservoir oils, and an increasing degree of mixing over time. Our finding confirms that the accumulated condensate gas in the Dibei area is mainly derived from the Jurassic source rocks. This allows the extent of prospective exploration to be better defined. Full article

Strategic breakthroughs have been made in the exploration and evaluation of Gulong shale oil in the Songliao Basin. However, the Heiyupao Depression, located near the Gulong Depression, hosts a thick section of the Qingshankou Formation shale that has not been extensively studied. This paper presents novel insights into the lithofacies characteristics, depositional environment, and reservoir features of the Qingshankou Formation shale in the Heiyupao Depression, with a specific focus on the origin and maturation of organic-rich shale. Four core wells were drilled, and 152 core samples were analyzed through a variety of techniques, including rock type classification, mineral composition, TOC content, rare earth elements, rock pyrolysis, organic matter type determination, and CT scanning. Results indicate that the Qingshankou shale is dominated by felsic compositions and Type I kerogen, with organic maturity varying across the section. Based on lithology, sedimentary structures, mineralogy, and organic matter abundance, five distinct lithofacies are identified: high-organic mud-rich felsic shale, high-organic sand-rich felsic shale, medium-organic sand-rich felsic shale, medium-organic massive shale, and low-organic sand-rich felsic shale. Notably, the Type A lithofacies (high-organic mud-rich felsic shale) is identified as a primary source rock due to its intergranular and organic matter pores, albeit with low porosity and poor connectivity. In contrast, the Type E lithofacies (low-organic sand-rich felsic shale) have high porosity, well-developed micro- and nano-scale pores, and strong connectivity, marking them as the primary reservoirs. The characteristics of this region differ significantly from those of Gulong shale oil, requiring different extraction strategies. The mineral composition of such shale is predominantly felsic rather than mixed. The findings not only provide theoretical support for the exploration of complex lacustrine shale in the Songliao Basin but also offer valuable insights for the resource development of similar non-marine shale systems worldwide. Full article

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ¹³C₁, δ¹³C₂ and δ¹³C₃ values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO₂ in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH₄) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH₄ from highly evolved, underlying coal-bearing source rocks. Consequently, the CH₄ content in the mixed gas is generally high (Ln (C₁/C₂) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area. Full article