Search Results (102)

In the northern part of the Songliao Basin, the Aonan Depression is a significant structural feature. It plays a crucial role in the relationship between tectonic evolution and deep natural gas accumulation mechanisms. While previous studies have revealed faulting and sedimentary characteristics in the region, the precise connection between tectonic evolution and hydrocarbon accumulation, particularly for deep natural gas, has not been systematically studied. This research uses structural modeling and stratigraphic restoration to reconstruct the tectonic evolution of the third section of the Shahezi Formation and develops a 3D geological model of the study area. The results show that the tectonic evolution of the Aonan Depression can be divided into three stages: rifting, sagging, and inversion. Each stage significantly controls hydrocarbon distribution. A self-sourced, self-storage gas system formed in the Shahezi Formation, while the Denglouku and Yingcheng formations exhibit a source–reservoir combination. The study reveals how tectonic evolution influences hydrocarbon accumulation and distribution on a regional scale. Based on these findings, a “rift-controlled source, sag-controlled storage, and structure-controlled trapping” accumulation model is proposed, providing new insights into tectonic evolution and hydrocarbon accumulation mechanisms, with important implications for similar basins’ exploration and structural studies. Full article

Judging from the current global exploration trend, ultra-deep layers have become the main battlefield for energy exploration. China has made great progress in the ultra-deep field in recent decades, with the Tarim Basin and Sichuan Basin as the focus of exploration. The Sichuan Basin is a large superimposed gas-bearing basin that has experienced multiple tectonic movements and has developed multiple sets of reservoir–caprock combinations vertically. Notably, the multi-stage platform margin belt-type reservoirs of the Sinian–Lower Paleozoic exhibit inherited and superimposed development. Source rocks from the Qiongzhusi, Doushantuo, and Maidiping formations are located in close proximity to reservoirs, creating a complex hydrocarbon supply system, resulting in vertical and lateral migration paths. The structural faults connect the source and reservoir, and the source–reservoir–caprock combination is complete, with huge exploration potential. At the same time, the ultra-deep carbonate rock structure in the basin is weakly deformed, the ancient closures are well preserved, and the ancient oil reservoirs are cracked into gas reservoirs in situ, with little loss, which is conducive to the large-scale accumulation of natural gas. Since the Nvji well produced 18,500 cubic meters of gas per day in 1979, the study of ultra-deep layers in the Sichuan Basin has begun. Subsequently, further achievements have been made in the Guanji, Jiulongshan, Longgang, Shuangyushi, Wutan and Penglai gas fields. Since 2000, two trillion cubic meters of exploration areas have been discovered, with huge exploration potential, which is an important area for increasing production by trillion cubic meters in the future. Faced with the ultra-deep high-temperature and high-pressure geological environment and the complex geological conditions formed by multi-stage superimposed tectonic movements, how do we understand the special geological environment of ultra-deep layers? What geological processes have the generation, migration and enrichment of ultra-deep hydrocarbons experienced? What are the laws of distribution of ultra-deep oil and gas reservoirs? Based on the major achievements and important discoveries made in ultra-deep oil and gas exploration in recent years, this paper discusses the formation and enrichment status of ultra-deep oil and gas reservoirs in the Sichuan Basin from the perspective of basin structure, source rocks, reservoirs, caprocks, closures and preservation conditions, and provides support for the optimization of favorable exploration areas in the future. Full article

Huhehu Sag is a sag with high exploration degree in Hailar Basin. With large sedimentary thickness, complete stratigraphic development and excellent oil generation conditions, it is the main oil- and gas-producing sag in Hailar Basin. The primary source rocks are the Nantun Formation, with the Tongbomiao and Damoguaihe Formations as secondary sources. Hydrocarbon accumulation periods in the sag were comprehensively analyzed using methodologies including source rock hydrocarbon generation-expulsion history, authigenic illite dating of reservoirs, and fluid inclusion homogenization temperature analysis. Results reveal two major accumulation stages: Stage 1 (125–90 Ma), corresponding to the depositional period of the Yimin Formation, represented the peak paleo-geothermal regime and the primary hydrocarbon accumulation phase. Intensive hydrocarbon generation and expulsion, coupled with robust migration dynamics, facilitated large-scale oil and gas pooling. Stage 2(65 Ma-now), from the deposition of Qingyuangang Formation to the present, uplift and denudation reduce the burial depth of source rocks, the hydrocarbon generation intensity is weakened. This phase involved secondary adjustments of pre-existing reservoirs and continued charging of newly generated hydrocarbons. The Huhehu Sag is a typical half-graben structure. Fault-block and fault-lithologic reservoirs dominate, distributed zonally along gentle and steep slopes. Lithologic reservoirs primarily occur near or within the central hydrocarbon-generating sub-sags. The most favorable hydrocarbon accumulation zones are located in the sub-sag centers and adjacent areas with high-quality reservoirs. Full article

The Qiongdongnan Basin constitutes a sedimentary basin characterized by elevated temperatures, significant overpressures, and abundant hydrocarbons. Investigations within this basin have identified hydrothermal fluid movements linked to overpressure conditions, comprising two vertically separated overpressured intervals. The shallow overpressure compartment is principally caused by a combination of undercompaction and clay diagenesis. In contrast, the deeper high-pressure compartment results from hydrocarbon gas generation. Numerical pressure modeling indicates late-stage (post-5 Ma) development of significant overpressure within the deep compartment. It is proposed that accelerated subsidence in the Pliocene-Quaternary initiated substantial gas generation, thereby promoting the formation of the deep overpressured system. Multiple organic maturation parameters, combined with fluid inclusion microthermometry, reveal a thermal anomaly adjacent to the upper boundary of the deep overpressured zone. This anomaly indicates vertical transport of hydrothermal fluids ascending from the underlying high-pressure zone. Laser Raman spectroscopy confirms the presence of both hydrocarbons and carbon dioxide within these migrating fluids. Integration of fluid inclusion thermometry with burial history modeling constrains the timing of hydrocarbon-carrying fluid charge to the interval from 4.2 Ma onward, synchronous with modeled peak gas generation and a phase of pronounced overpressure buildup. We propose that upon exceeding the fracture gradient threshold, fluid pressure triggered upward migration of deeply sourced, hydrocarbon-enriched fluids through hydrofracturing pathways. This process led to localized dissolution and fracturing near the top of the deep overpressured system, while simultaneously facilitating significant hydrocarbon accumulation and forming preferential accumulation zones. These findings provide critical insights into petroleum exploration in overpressured sedimentary basins. Full article

The Lower Submember of the Second Member of the Lianggaoshan Formation (LGS2-LS) in the Fuling area, southeastern Sichuan Basin, represents the deepest lacustrine depositional stage of the formation and constitutes an important target for shale oil and gas exploration. Based on core observations, thin-section petrography, X-ray diffraction, geochemical analyses, and sedimentary facies interpretation from representative wells, this study characterizes the lithofacies types, sedimentary environments, and depositional evolution of the LGS2-LS. Results show that the LGS2-LS is dominated by clay–quartz assemblages, with average clay mineral and quartz contents of 44.6% and 38.8%, respectively, and can be subdivided into shallow and semi-deep lacustrine subfacies comprising eight microfacies. Geochemical proxies indicate alternating warm-humid and hot-arid paleoclimatic phases, predominantly freshwater conditions, variable redox states, and fluctuations in paleoproductivity. Sedimentary evolution reveals multiple transgressive–regressive cycles, with Sub-layer 6 recording the maximum water depth and deposition of thick organic-rich shales under strongly reducing conditions. The proposed sedimentary model outlines a terrigenous clastic lacustrine system controlled by lake-level fluctuations, transitioning from littoral to shallow-lake to semi-deep-lake environments. The distribution of high-quality organic-rich shales interbedded with sandstones highlights the LGS2-LS as a favorable interval for shale oil and gas accumulation, providing a geological basis for further hydrocarbon exploration in the southeastern Sichuan Basin. Full article

The Pinghu Oil and Gas Field in the East China Sea Shelf Basin represents a significant offshore hydrocarbon-producing region in East Asia. However, the Paleogene hydrocarbon system in the Pinghu Oil and Gas Field is complex, and the fluid properties, charging stages, and hydrocarbon accumulation process are still unclear. A comprehensive integrated analysis of the hydrocarbon accumulation characteristics, fluid properties, temperature pressure regimes, primary hydrocarbon sources and origins (genesis), charging stages, preservation conditions, and evolutionary history of hydrocarbon accumulation have been studied by utilizing a series of well data, oil and gas geochemical parameters, carbon isotope, and fluid inclusion analyses. Hydrocarbon charging in the Huagang Formation experienced one stage, and the crude oil is characterized as light and conventional, exhibiting low density and viscosity, a low pour point, and low contents of wax, resin, and sulfur. In contrast, the reservoir of the overpressured Pinghu Formation experienced a two-stage hydrocarbon charging process (oil filling and gas filling), exhibiting higher density, viscosity, and wax content compared to the Huagang Formation. The hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized in three different stages, including the oil filling period (10–5 Ma), gas filling period (5–2 Ma), and oil and gas adjustment period. The Pinghu Oil and Gas Field, especially in the lower Pinghu Slope Belt (Fangheting Structure), has good potential for further exploration. Full article

To elucidate the mechanisms governing hydrocarbon accumulation and phase evolution in the deep–ultradeep reservoirs of the Mo-Yong area, this study integrated 2D basin modeling and multi-component phase state simulation techniques, investigating the differences in maturity and hydrocarbon generation history between the Fengcheng Formation (P₁f) and the Lower Wuerhe Formation (P₂w) source rocks, as well as their coupling relationship with fault activity in controlling hydrocarbon migration, accumulation, and phase evolution. The results indicate that the P₁f and P₂w in the Mo-Yong area source rocks differ in thermal maturity and hydrocarbon generation evolution. The dual-source charging from both the P₁f and P₂w significantly enhances hydrocarbon accumulation number, volume, and saturation. The temporal-spatial coupling between peak hydrocarbon generation and multi-stage fault reactivation not only facilitates extra-source accumulation but also drives condensate reservoir formation through gas-oil ratio elevation and light-component enrichment. Based on these results, a model of hydrocarbon accumulation and phase evolution of deep reservoirs was proposed. The model elucidates the fundamental geological principle that source-fault spatiotemporal coupling controls hydrocarbon enrichment degree, while phase differentiation determines reservoir fluid types. Full article

This study provides a detailed geochronological paragenesis of fracture systems from the Upper Jurassic petroleum source formation in NE Iraq, utilizing U-Pb dating, integrated with microprobe analyses and petrographic studies. Five fracturing stages are recognized (FI–FV), indicating significant tectonic and temperature changes from the Late Jurassic to Pliocene times (approximately 5.2–5.5 Ma). The burial history curve shows continuous subsidence events, starting with initial burial of the Barsarin Formation reaching depths of 1000–1200 m by 110 Ma, this depth interval coincides with the first fracturing stage (FI). The buffered system of FI by pristine facies and geometrical cross-cutting of FI with early stylolite formation show a prior formation of stylolite. Subsequent fracturing stages FII (28.6 ± 2 Ma, Oligocene) and FIII (19.83 ± 0.43 Ma, Early Miocene) were contemporaneous with tectonic deformation phases and hydrocarbon generation times. Microprobe and optical analyses demonstrate variations in mineralogical composition, particularly in FIV/FV-filled calcite and dolomite cements (12.2 ± 1.5 Ma and 5.5 Ma), highlighting the periods of conduit formation for the hydrocarbon migration. Backscattered electron (BSE) imaging reveals a textural alteration of these cements, especially those associated with fluorite precipitation, which further support the hydrothermal entrapment associated with the hydrocarbon migration. The hydrocarbon entrapment appeared in at least two episodes under subsurface setting under temperatures exceeding 100 °C. In summary, the significant meaningful ages and compositional analyses obtained from this study reveal crucial insights into the dynamics of fracture-filling cements and hydrocarbon entrapment mechanisms within the petroleum source rock formation. The novelty of these data would enhance our understanding of the complex relationship between structural geology and migration conduits, highlighting the influence of fracture-filling cements on hydrocarbon accumulation and reservoir quality as a main target for hydrocarbon field development. Full article

This study investigates the uplift and exhumation history of the southern segment of the western margin of the Ordos Basin using low-temperature thermochronology, including zircon (U-Th)/He (ZHe), apatite fission-track (AFT), and apatite (U-Th)/He (AHe) data, combined with thermal history modeling. The study area exhibits a complex structural framework shaped by multiple deformation events, leading to the formation of extensively developed fault systems. Such faulting can adversely affect hydrocarbon preservation. To better constrain the timing of fault reactivation in this area, we carried out an integrated study involving low-temperature thermochronology and burial history modeling. The results reveal a complex, multi-phase thermal-tectonic evolution since the Late Paleozoic. The ZHe ages (291–410 Ma) indicate deep burial and heating related to Late Devonian–Early Permian tectonism and basin sedimentation, reflecting early orogenic activity along the western North China Craton. During the Late Jurassic to Early Cretaceous (165–120 Ma), the study area experienced widespread and differential uplift and cooling, controlled by the Yanshanian Orogeny. Samples on the western side of the fault show earlier and more rapid cooling than those on the eastern side, suggesting a fault-controlled, basinward-propagating exhumation pattern. The cooling period indicated by AHe data and thermal models reflects the Cenozoic uplift, likely induced by far-field compression from the rising northeastern Tibetan Plateau. These findings emphasize the critical role of inherited faults not only as thermal-tectonic boundaries during the Mesozoic but also as a pathway for hydrocarbon migration. Meanwhile, thermal history models based on borehole data further reveal that the study area underwent prolonged burial and heating during the Mesozoic, reaching peak temperatures for hydrocarbon generation in the Late Jurassic. The timing of major cooling events corresponds to the main stages of hydrocarbon expulsion and migration. In particular, the differential uplift since the Mesozoic created structural traps and migration pathways that likely facilitated hydrocarbon accumulation along the western fault zones. The spatial and temporal differences among the samples underscore the structural segmentation and dynamic response of the continental interior to both regional and far-field tectonic forces, while also providing crucial constraints on the petroleum system evolution in this tectonically complex region. Full article

In end-stage renal disease (ESRD), the accumulation of solutes normally excreted by the kidneys contributes to multiple complications, including vascular calcification (VC), a key factor in the heightened cardiovascular risk seen in these patients. Among VC drivers, hyperphosphatemia and the uremic milieu are major contributors. Kynurenine, a tryptophan metabolite classified as a uremic toxin, may further exacerbate this process. This study investigated whether kynurenine amplifies high phosphate (Pi)-induced calcification in human aortic endothelial cells (HAEC). Cells were treated with Pi and kynurenine for up to seven days. Kynurenine increased Pi-induced calcium deposition by 36%, accompanied by enhanced endothelial-to-mesenchymal transition (EndMT) and osteoblastic differentiation. Mechanistically, kynurenine activated the aryl hydrocarbon receptor (AhR) pathway, and pharmacological inhibition of AhR partially attenuated this effect. These findings suggest that kynurenine contributes to VC in ESRD by potentiating phosphate-induced endothelial dysfunction via AhR signaling. Full article

Mining activities have long-term impacts on the environment even after the active stage. Historical mines developed in the 19th and 20th centuries for tin, copper, and mainly iron ore are located in the Pitkäranta area (Karelia, Russia). These objects are considered in our research as natural–anthropogenic sites of long-term water–rock interaction. Waters from flooded mines are the subject of this research. Redox conditions, pH, dissolved oxygen content, conductivity, and water temperature were determined during field work. The chemical composition of natural waters was determined by ICP-MS, ICP-AES, ion chromatography, potentiometric titration, and spectrophotometry. Our investigation showed that the mine waters are fresh and predominantly calcium–magnesium hydrocarbonate; most samples showed elevated sulfate ion contents. Circumneutral pH values and the absence of extremely high concentrations of heavy metals indicate neutral mine drainage. However the calculation of the accumulation coefficient showed the highest levels for siderophile elements relative to the corresponding data of the geochemical regional background. Moreover, zinc has the highest content in the series of heavy metal(loid)s considered. The maximum concentration of zinc was determined in the water of one of the shafts of the Lupikko mine, i.e., 5205 µg/L. The accumulation of heavy metals occurs in the process of long-term interaction of water–rock–organic matter under conductive redox conditions. Overall, the research highlighted the relevance of investigating the geochemistry of historical mines in the Pitkäranta area both from the perspective of environmental safety and the preservation of mining sites for scientific and educational purposes. Full article

Deep carbonate reservoirs have garnered significant attention and demonstrated great potential for oil and gas exploration in recent years. The Majiagou Formation in the Ordos Basin has received much attention for its deep oil and gas deposits recently. However, the issue of fluid evolution within the great depth has been overlooked, and the relationship between fluid flow and the gas accumulation process remains unclear. This paper aims to explore the fluid evolution and its relationship with the gas accumulation, which poses a challenge for further petroleum exploration. To achieve this, petrological studies on dolomite samples were carried out and four types of secondary cements were identified: early gypsum-moldic pore-filling calcite, late gypsum-moldic pore-filling calcite, dissolution pore-filling calcite and fracture-filling calcite. Subsequently, an interdisciplinary approach that integrates petrography observation, microthermometry, laser Raman analysis of fluid inclusions, and carbon and oxygen isotope tests on these types of cements is employed to elucidate the fluid flow evolution. These investigations revealed that four different stages of inorganic fluid activity were coeval with two stages of organic fluid activity. The two stages of organic fluid flows were significantly important for petroleum accumulation. In the late Triassic to early Jurassic, there was small-scale liquid oil accumulation, which was associated with the second stage of fluids. In the early Cretaceous, there was large-scale gas accumulation, which was associated with the fourth stage of fluids. This research is crucial for understanding the fluid flow process and its relationship with hydrocarbon accumulation in deeply buried carbonate formations. Full article

A comprehensive paleoecological study of a forested bog located in the middle taiga subzone of northeastern European Russia was carried out. According to the ¹⁴C radiocarbon dating and botanical composition analysis, the bog began forming 8200 calibrated years ago, evolving in three stages from grassy wetlands to its current state as a pine-Sphagnum peatland. Analysis revealed substantial carbon storage (81.4 kg m⁻²) within the peat deposit. Macrocharcoal particles were consistently present throughout the peat deposits, demonstrating continuous fire activity across the bog’s developing. High charcoal particle accumulation rates occurred not only during warm periods like the Holocene thermal maximum but also during colder and wetter periods. These periods include recent centuries, when high charcoal accumulation rates are likely due to increased human activity. Statistical analysis showed significant relationships between macrocharcoal content and several peat characteristics: higher charcoal levels correlated with increased soil carbon (r = 0.6), greater aromatic compounds (r = 0.8), and elevated polycyclic aromatic hydrocarbons (r = 0.7), all with p < 0.05. These findings highlight how fire has consistently shaped this ecosystem’s development and carbon storage capacity over millennia, with apparent intensification during recent centuries potentially linked to anthropogenic influences on fire regimes in the boreal zone. Full article

In order to clarify the pore evolution and coupling characteristics with hydrocarbon charging in the deep-buried ultra-tight sandstone reservoirs of the second member of Xujiahe Formation (hereinafter referred to as the Xu 2 Member) on the eastern slope of the Western Sichuan Depression, this study integrates burial history and thermal history with analytical methods including core observation, cast thin section analysis, scanning electron microscopy, carbon-oxygen isotope analysis, and fluid inclusion homogenization temperature measurements. The Xu 2 Member reservoirs are predominantly composed of lithic sandstones and quartz-rich sandstones, with authigenic quartz and carbonates as the main cementing materials. The reservoir spaces are dominated by intragranular dissolution pores. The timing of reservoir densification varies among different submembers. The upper submember underwent compaction during the Middle-Late Jurassic period due to the high ductility of mudstone clasts and other compaction-resistant components. The middle-lower submembers experienced densification in the Late Jurassic period. Late Cretaceous tectonic uplift induced fracture development, which enhanced dissolution in the middle-lower submembers, increasing reservoir porosity to approximately 5%. Two distinct phases of hydrocarbon charging are identified in the Xu 2 Member. The earlier densification of the upper submember created unfavorable conditions for hydrocarbon accumulation. In contrast, the middle-lower submembers received hydrocarbon charging prior to reservoir densification, providing favorable conditions for natural gas enrichment and reservoir formation. Three sweet-spot reservoir development patterns are recognized: paleo-structural trap + (internal source rock) + source-connected fracture assemblage type, paleo-structural trap + internal source rock + late-stage fracture assemblage type, and paleo-structural trap + (internal source rock) + source-connected fracture + late-stage fracture assemblage type. Full article

The Sichuan Basin is a key area for shale gas energy exploration in China. However, the pore evolution mechanism and accumulation effect of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin remain poorly understood. In this study, the pore structure characteristics of shale reservoirs and the dynamic accumulation and evolution of shale gas in the northern Fuling and Yuanba areas were systematically analyzed by adsorption experiments, high-pressure mercury injection joint measurement, and thermal simulation experiments. The results indicate the following: (1) The continental shale in the study area is predominantly composed of mesopores (10–50 nm), which account for approximately 55.21% of the total pore volume, followed by macropores (5–50 μm) contributing around 35.15%. Micropores exhibit the lowest proportion, typically less than 10%. Soluble minerals such as clay minerals and calcite significantly promote pore development, while soluble organic matter may block small pores during hydrocarbon generation, which facilitates the enrichment of free gas. (2) The thermal simulation experiment reveals that pore evolution can be divided into two distinct stages. Prior to 450 °C, hydrocarbon generation leads to a reduction in pore volume due to the compaction and transformation of organic matter. After 450 °C, organic matter undergoes cracking processes accompanied by the formation of shrinkage fractures, resulting in the development of new macropores and a significant increase in pore volume. This indicates that thermal energy input during the thermal evolution stage plays a key role in reservoir reconstruction. (3) The early Jurassic sedimentary environment controls the enrichment of organic matter, and the Cretaceous is the key period of hydrocarbon accumulation. Hydrocarbon generation and diagenesis synergistically promote the formation of gas reservoirs. The Cenozoic tectonic activity adjusted the distribution of gas reservoirs, and finally formed the enrichment model with the core of source–reservoir–preservation dynamic matching. For the first time, combined with dynamic thermal simulation experiments, this study clarifies the stage characteristics of pore evolution of continental shale and identifies the main controlling factors of shale gas accumulation in the Lower Jurassic in northeastern Sichuan, which provides a theoretical basis for continental shale gas exploration and energy resource development, offering important guidance for optimizing the selection of exploration target areas. Full article