Junggar Basin Research Articles

Fluid inclusion evidence for overpressure-induced shale oil accumulation

Abstract Shale oil is becoming increasingly important in the global energy market, but its accumulation mechanism is not fully understood. We present novel and direct fluid inclusion data from the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. Shortite veins in this source rock contain abundant two-phase gas-liquid hydrocarbon inclusions and coeval aqueous inclusions. The inclusions have highly variable degrees of bubble filling (5–80 vol% vapor) and homogenization temperature differences between oil and aqueous inclusions (~50 °C), which demonstrate that fluid (oil-gas-water) immiscibility occurred at high pressures. The hydrocarbon inclusions record different levels of fluid over-pressure (32.9–43.0 MPa), with a paleopressure coefficient of 1.3–1.7. Episodic fluid over-pressure release resulted in shale oil accumulation, with faults/fractures acting as important migration pathways. Oil from deeper and more mature source rocks within the Fengcheng Formation was expelled upward to the shale oil reservoir. These processes are common and important in shale oil systems. These results show that the accumulation of unconventional hydrocarbons occurs pervasively within the reservoirs, and fluid displacement is critical in exploration and exploitation.

Discovery of Seismites in the Carboniferous Formation of the Shibei Sag (China) and Its Petroleum Geological Significance

To promote oil and gas exploration of the Carboniferous formation in the Shibei sag, the northeastern margin of Junggar Basin, recently drilled rocks from Well ZB6 with typical seismics were characterized. Through systematic core observation, the identification marks of seismites were described, a vertical sequence of seismites was established, and its oil and gas geological significance was analyzed. The results show that the seismites have typical identification marks, such as soft-sediment deformation structures (including five typical marks: liquefied stone vein, liquefied crinkled deformation structure, ball–pillow structure, flame structure and load cast, water release structure and liquefied breccia), brittle fracture structures (including three typical marks: seismic fractures, synsedimentary microfractures and seismic fracture rock) and special rock types, such as seismic grain-supported conglomerates. The stratigraphic succession reconstructed in Well ZB6 was characterized, from base to top, by (1) a basal non-seismic interval; (2) a seismic interval made up of a grain-supported conglomerate level, brittle fracture level, soft-sediment deformation level; and (3) a non-seismic interval. The discovery of seismites has oil and gas geological significance for improving reservoir performance and forming favorable source–reservoir–cap assemblages. The research describes the new reservoir genetic type and exploration direction of the Carboniferous formation in the Shibei sag (China), which has important guiding significance for the next step of oil and gas exploration.

Prediction of multiscale laminae structure and reservoir quality in fine-grained sedimentary rocks: The Permian Lucaogou Formation in Jimusar Sag, Junggar Basin

Fine-grained sedimentary rocks have become a research focus as important reservoirs and source rocks for tight and shale oil and gas. Laminae development determines the accumulation and production of tight and shale oil and gas in fine-grained rocks. However, due to the resolution limit of conventional logs, it is challenging to recognize the features of centimeter-scale laminae. To close this gap, complementary studies, including core observation, thin section, X-ray diffraction (XRD), conventional log analysis, and slabs of image logs, were conducted to unravel the centimeter-scale laminae. The laminae recognition models were built using well logs. The fine-grained rocks can be divided into laminated rocks (lamina thickness of <0.01 m), layered rocks (0.01–0.1 m), and massive rocks (no layer or layer spacing of >0.1 m) according to the laminae scale from core observations. According to the mineral superposition assemblages from thin-section observations, the laminated rocks can be further divided into binary, ternary, and multiple structures. The typical mineral components, slabs, and T 2 spectrum distributions of various lamina types are unraveled. The core can identify the centimeter–millimeter-scale laminae, and the thin section can identify the millimeter–micrometer-scale laminae. Furthermore, they can detect mineral types and their superposition sequence. Conventional logs can identify the meter-scale layers, whereas image logs and related slabs can identify the laminae variations at millimeter–centimeter scales. Therefore, the slab of image logs combined with thin sections can identify laminae assemblage characteristics, including the thickness and vertical assemblage. The identification and classification of lamina structure of various scales on a single well can be predicted using conventional logs, image logs, and slabs combined with thin sections. The layered rocks have better reservoir quality and oil-bearing potential than the massive and laminated rocks. The laminated rocks’ binary lamina is better than the ternary and multiple layers due to the high content of felsic minerals. The abovementioned results build the prediction model for multiscale laminae structure using well logs, helping sweet spots prediction in the Permian Lucaogou Formation in the Jimusar Sag and fine-grained sedimentary rocks worldwide.

Effect of microscopic pore structures on ultrasonic velocity in tight sandstone with different fluid saturation

Microcosmic details of pore structure are the essential factors affecting the elastic properties of tight sandstone reservoirs, while the relationships in between are still incompletely clear due to the fact that quantitative or semi-quantitative experiments are hard to achieve. Here, three sets of tight sandstone samples from the Junggar Basin are selected elaborately based on casting thin sections, XRD detection, and petro-physical measurement, and each set is characterized by a single varied microcosmic factor (pore connectedness, pore type, and grain size) of the pore structure. An ultrasonic pulse transmission technique is conducted to study the response of elastic properties to the varied microcosmic details of pore structure in the situation of different pore fluid (gas, brine, and oil) saturation and confining pressure. Observations show samples with less connectedness, inter-granular dominant pores, and smaller grain size showed greater velocities in normal conditions. V p is more sensitive to the variations of pore type, while V s is more sensitive to the variations of grain size. Samples with better connectedness at fluid saturation (oil or brine) show greater sensitivity to the confining pressure than those with gas saturation with a growth rate of 6.9% to 11.9%, and the sensitivity is more likely controlled by connectedness. The pore types (inter-granular or intra-granular) can be distinguished by the sensitivity of velocities to the variation of pore fluid at high confining pressure (> 60 MPa). The samples with small grain sizes tend to be more sensitive to the variations of confining pressure. With this knowledge, we can semi-quantitatively distinguish the complex pore structures with different fluids by the variation of elastic properties, which can help improve the precision of seismic reservoir prediction for tight sandstone reservoirs.

Genesis of authigenic clay minerals and their impacts on reservoir quality in tight conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu Sag, Junggar Basin, Western China

Authigenic clay minerals are widely distributed and considerably affect the reservoir quality of the conglomerate reservoirs in the Triassic Baikouquan Formation (BF), Mahu Sag, Junggar Basin, Western China. Their occurrences, origins, and impacts on reservoir quality were investigated utilizing petrographical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), Mercury intrusion capillary pressure (MICP), and fractal analysis. Pore-lining chlorite coatings (Ch1) and pore-filling chlorite aggregates (Ch2), respectively, originate from smectite precursors and directly precipitate from pore water. The first-stage kaolinite (K1) formed by plagioclase dissolution appears as flake-shaped single crystals, whereas the second-stage kaolinite (K2) formed by K-feldspar particle dissolution appears as complete false-hexagonal single crystals and vermiform-shaped aggregates. Smectite transformation produces first-stage illite (I1) with honeycomb-like shaped aggregates. The second-stage illite (I2) displaying a flake-shaped occurrence with a directional arrangement is attributed to the transformation of K-feldspar. Based on the burial history, contact relationship of diagenetic minerals, and hydrocarbon charging period, the paragenetic sequence of the conglomerate reservoir is summarized.Afterward, Neimark's fractal model is employed to calculate the fractal dimensions (Fd) of the reservoir with different dominant clay minerals. It is revealed that pore-lining chlorites have the smallest Fd values (<2.5) and their pore size reached 0.6 μm, whereas pore-filling chlorites possessed the greatest heterogeneity with the narrowest pore size distribution. Illite and kaolinite affect reservoir quality in both favorable and detrimental ways. Eventually, the pore evolution within different lithofacies was analyzed. The first promising reservoirs are well-sorted fine-grained conglomerates that have experienced two phases of oil charging, wherein well-developed primary intergranular apertures, secondary dissolution apertures, and kaolinite are commonly observed. Medium-grained conglomerate reservoirs with high clay amounts and poor sorting have been subjected to rapid and intense compaction, resulting in the worst reservoir quality while no dissolution occurred. This work may provide a useful reference for hydrocarbon exploitation of reservoirs which formed under similar geological conditions.

Chemometric Classification and Geochemistry of Crude Oils in the Eastern Fukang Sag, Junggar Basin, NW China

Thirty oil samples collected from the eastern Fukang Sag were analyzed geochemically for their biomarkers and carbon isotopic compositions. The chemometric methods of principal component analysis and hierarchical cluster analysis, employed to thirteen parameters indicating source and depositional environment, classified the oil samples into three genetically distinct oil families: Family A oils were mainly derived from lower aquatic organisms deposited in a weakly reducing condition of fresh–brackish water, Family B oils came from a source containing predominantly terrigenous higher-plant organic matter laid down in an oxidizing environment of fresh water, and Family C oils received sources from both terrigenous and marine organic matter deposited in a weakly oxidizing to oxidizing environment of brackish water. Indirect oil–source correlations implied that Family A oils were probably derived from Permian source rocks, Family B oils originated mainly from Jurassic source rocks, and Family C oils had a mixed source of Carboniferous and Permian. Biomarker maturity parameters revealed that all three families of oils were in the mature stage. However, Family A oils were relatively less mature than Family B and Family C oils.

Occurrence state and oil content evaluation of Permian Fengcheng Formation in the Hashan area as constrained by NMR and multistage Rock-Eval

The Hashan area, neighboring the Mahu Sag that is rich in the shale oil resources, showed commercial oil flow in the corresponding lacustrine shales of the Lower Permian Fengcheng Formation (P1f) with reserve scale approximately 789 million tons, presenting great potential for oil exploration. Despite their geographical proximity, the hydrocarbon occurrence and oil-bearing capacity of shale in the Hashan area and Mahu Sag greatly differ owing to the complex tectonic evolution. Therefore, understanding the occurrence state and oil content of the P1f in the Hashan area is crucial for ongoing shale oil exploration activities and the development of the northwestern margin of the Junggar Basin. In this study, an integrated investigation, including petrological observations, scanning electron microscopy (SEM) observation, analysis of nuclear magnetic resonance (NMR) T1–T2 spectra, and conventional and multistage Rock-Eval pyrolysis methods were conducted to evaluate the occurrence state and oil content of the P1f shale in the Hashan area. The results indicate that plagioclase (average 30.7%) and quartz (24.1%) dominate the mineral compositions of the P1f shale samples. A method involving quartz–plagioclase–carbonate minerals is proposed to conduct lithofacies classification. In the Hashan area, the organic matter abundance in the P1f shale is scaled in fair to good range, the thermal maturity ranges from immature to early mature stage, and the primary organic matter types are Types I and II1. Intergranular and dissolution pores are the two most common pore types. The free oil is mostly found in the pores and microfractures of the mineral matrix, whereas the adsorbed oil is mostly adsorbed on the surfaces of kerogen and clay minerals. The high organic matter abundance, quartz content, and porosity account for substantial increase in the oil content, the area rich in shale oil resources coincides with that rich in free oil. The most favorable lithofacies in the Hashan area is the calcareous mudstone/shale, which hosts the highest free oil content (average 2.49 mg), total oil content (15.02 mg/g), organic matter abundance (TOC = 1.88% and S1+S2 = 20.54 mg/g) and porosity (5.97%).

Flexible learning tree augmented naïve classifier and its application

Tree augmented naïve Bayes classifier (TAN) has been widely used in machine learning and data mining. To improve the flexibility and classification performance of TAN, this paper proposes a Flexible Tree Augmented Naïve Bayes classifier (FTAN). In the FTAN, the mutual information contribution rate is used to measure the dependencies between attributes in the process of building the maximum weighted spanning tree. Then, a flexible filtering method is adopted to filter out edges with weak dependencies between attributes by dynamically adjusting the threshold. A range of experiments on UCI datasets reveals that the FTAN exhibits considerable advantages over other popular algorithms in terms of the 0-1 loss and class probability root mean square error. The FTAN is used to solve the problem of favourable distribution area prediction for the remaining oil and gas resources of the Jurassic Sangonghe Formation in the Junggar Basin. The application results show the effectiveness and superiority of the FTAN method, favourable areas of oil and gas resources are selected based on the FTAN prediction results. This provides a decision-making basis for optimising drilling strategies and oil and gas exploration targets.

Improvement of Gas Compressibility Factor and Bottom-Hole Pressure Calculation Method for HTHP Reservoirs: A Field Case in Junggar Basin, China

Gas reservoirs discovered in the southern margin of the Junggar Basin generally have high temperatures (up to 172.22 °C) and high pressures (up to 171.74 MPa). If using the PVT laboratory to get the gas compressibility factor, data from the laboratory are so little that it will not satisfy the demands of reservoir engineering calculations. There are many empirical correlations for calculating the Z-factor; however, these correlations give large errors at high gas reservoir pressures. The errors in estimating the Z-factor will lead to large errors in estimating all the other gas properties such as gas formation volume factor, gas compressibility, and gas in place. In this paper, a new accurate Z-factor correlation has been developed based on PVT data by correcting the high-pressure part of the most commonly used Dranchuk-Purvis-Robinson Correlation. Multivariate nonlinear regression is used to establish the independent variable function of pseudo-critical temperatures and pressures. By comparing it with the PVT data, the DPR correlation is continuously corrected to be suitable for ultra-deep gas reservoirs with HTHP. The new correlation can be used to determine the Z-factor at any pressure range, especially for high pressures, and the error is less than 1% compared to the PVT data. Then, based on the corrected Z-factor, the Cullender-Smith method is used to calculate the bottom hole pressure in the middle of the reservoir. Finally, the Z-factor under reservoir conditions of well H2 is predicted and the Z-factor chart at different temperatures is provided.

Petrochemical and geochronological data of Permian-Lower Triassic clastic sedimentary rocks in the northwestern Junggar basin, NW China: Implications for provenance, tectonism and paleoclimate

The Permian clastic sediments in the Mahu sag offer outstanding conditions to test the control of tectonism and paleoclimate on sedimentation in a rift basin. A synthesis of petrological and geochemical analyses of sandstones, zircon U–Pb geochronology of granitic conglomerates, and principal component analysis have been used to investigate the source composition and chemical weathering indices. The rare earth and trace element compositions of 16 sandstone samples are consistent with first cycle sources from the Carboniferous–Lower Permian mafic and felsic igneous rocks in West Junggar. Lower Permian sandstones contain abundant volcanic lithic clasts and plagioclase grains, and have high Na2O, CaO, Sr and V, suggesting a coeval proximal volcanic source in Central West Junggar during the syn-rift stage. Middle Permian sandstones consist of trachyte and rhyolite clasts, and quartz and albite grains, and show a gradual increase of Th, U and SiO2, indicating an expansion of source areas to more distant Southern and Northern West Junggar during the post-rift stage. In the Lower Triassic, an abrupt increase in the percentages of quartz and K-feldspar, as well as the zircon U–Pb geochronology of granite-clast conglomerates (290–330 Ma), all indicate regional uplift and unroofing of Carboniferous–Permian granitic plutons in West Junggar during the tectonic inversion stage at the Permian-Triassic boundary. Various chemical weathering indices indicate cold and arid climate conditions during the early Permian, followed by a transition to warm and humid climatic conditions. Comprehensive analysis of petrography and geochemistry sheds a new light for studying the source-to-sink evolution of a rift basin, and has further implication for paleoclimate fluctuation and change.

Petroleum Geology and Exploration of Deep-Seated Volcanic Condensate Gas Reservoir around the Penyijingxi Sag in the Junggar Basin

Many types of volcanic rock oil and gas reservoirs have been found in China, showing great petroleum exploration potential. Volcanic reservoir also is one of the key fields of exploration in the Junggar Basin and mainly concentrated in the middle and shallow layers, while the deep volcanic rock and natural gas fields have not been broken through. Based on comprehensive analysis of core observation, single well analysis, reservoir description, source rocks evaluation, combined with seismic data and time-frequency electromagnetic technology, multiple volcanic rock exploration targets were identified, and industrial oil and gas flow was obtained in the well SX 16 of the Penyijingxi Sag, western Junggar Basin. It is believed that the deep Permian source rocks have relatively higher natural gas generation potential and volcanic breccia usually have large reservoir space. And the mudstone of the Upper Wuerhe Formation played as the role of caprock. The success of exploration well SX16 has achieved a major breakthrough in natural gas exploration in the Penyijingxi Sag, which has essential guiding significance for the exploration of deep volcanic rocks and large-scale gas exploration in the Junggar Basin.

Hydraulic fractures evaluation of the glutenite and the effects of gravel heterogeneity based on cores

A demonstration area was established on the north slope of the Mahu Depression, Junggar Basin, NW China to carry out the hydrofracturing experiment and a cored well was designed to investigate hydraulic fractures. 345 fractures, comprising HFs, natural fractures, core-handling fractures, and drilling-induced fractures, were harvested from four continuous cores of about 323.19 m that contained mudstone, sandstone, and conglomerate. The lithology of the core is dominated by the conglomerate, which is characterized by coarse gravel size, poor sorting, and gravel support. Firstly, this paper identifies different fractures by integrating the core observation, imaging logs, and CT scans. The HF in the glutenite reservoir was divided into penetrating-gravel fractures and bypassing-gravel fractures based on the fracture propagation path and fracture surface geometry. Secondly, the occurrence and density of HFs were characterized, respectively. The HF has a dip of 80–90° and two trends of 0°–20° and 160°–220°. The fracture density presents strong heterogeneity over depth and the number of penetrating-gravel fractures is nearly twice of that bypassing-gravel fractures. Besides, no significant proppants were observed on the fracture surface, while it was identified in the rock debris. Thirdly, the gravel size and orientation were selected to investigate the impact of gravel heterogeneity on HFs. The result showed that the larger gravel size and greater acute angle between gravel orientation and HFs propagation orientation are conducive to the development of penetrating-gravel fractures. Finally, the impact of fractured wells on HFs was studied. The fracture density is closely related to the distance between fractures and the perforation site, Cluster spacing, and slickwater. Higher fracture density is a result of closer spacing between HFs and the perforation site, smaller cluster spacing, and a higher percentage of slickwater. The insight of this paper is expected to provide some references for the hydrofracturing operation in oilfields and current experimental and numerical investigation.

Geological characteristics and resource potential of shale oil in major basins of China

China shale oil can be classified as interlayer shale oil (in sandstone, carbonate, and diamictite) and genuine shale oil. Considering the characteristics and strong heterogeneity of continental shales, it is recommended to evaluate the interlayer shale oil resources using the elemental volume method based on pore volume, and the genuine shale oil resources using the elemental weight method based on oil content. Four key parameters for genuine shale oil resource evaluation (i.e., S 1, TOC, R o, and shale thickness) and three key parameters for interlayer shale oil resource evaluation (i.e., interlayer thickness, porosity, and oil saturation) are determined, and the lower limits of parameters are defined accordingly. The evaluation results show that the geological resources of genuine shale oil in Qing-1 member of Songliao Basin are 52.23 × 108 t; the geological resources of shale oil in Chang-73 sub-member of Ordos Basin are 66.80 × 108 t, including 27.73 × 108 t interlayer shale oil and 39.07 × 108 t genuine shale oil; the geological resources of shale oil in Lucaogou Formation of Junggar Basin are 15.62 × 108 t, including 11.99 × 108 t interlayer shale oil and 3.63 × 108 t genuine shale oil. This study provides a reference for exploration decision of shale oil in China.

Key factors controlling deep Carboniferous volcanic reservoirs in the east slope of Mahu Sag, Junggar Basin, NW China

Considering the complex factors controlling volcanic reservoirs, the Carboniferous strata in the eastern slope area of the Mahu Sag (ESMS) in the northwestern Junggar Basin (NJB) were investigated using rock cores, thin sections, scanning electron microscope (SEM), physical properties, major elements, X-ray fluorescence (XRF), well logging, and seismic data. The volcanic rocks revealed by drilling are mostly weathering crust reservoirs (WCRs), the formation of which in and around the study area is significantly controlled by weathering and leaching (WL). Most types of volcanic rock can be improved by long-term weathering. Favorable reservoirs in the ESMS are often developed within 150 m below the tectonic unconformity boundary at the top of the Carboniferous. The longer the weathering duration, the better are the overall quality of the WCRs. Weathering duration of about 40 Ma is probably an important threshold in the NJB. Ultra-long leaching of atmospheric water and strong late dissolution of acidic fluids before oil and gas accumulations are important for reservoir development and petroleum accumulation in volcanic strata filled with authigenic minerals, especially calcite. The early regional tectonic movement affected the volcanic eruption and controlled the lithofacies distribution. The linear density of fractures was negatively correlated with the distance from the main controlling fault. Owing to the relatively weak filling, high-angle fractures contribute significantly to the reservoir permeability. The physical properties of volcanic breccia are better than those of tuff, and the porosity, permeability, and fracture density of andesite are higher than those of basalt. The physical properties of near-source facies belts of a volcanic edifice are better than those of far-source facies ones. Favorable exploration areas are the structural highs and fault zones where the duration of WL is more than 40 Ma, explosive facies and effusive facies near the crater are developed, or the inherited ancient buried hills transformed by faults and fractures near excellent source rocks, where the dissolution of atmospheric water and organic acidic fluids are strong.

Organic matter accumulation in lacustrine shale of the Permian Jimsar Sag, Junggar Basin, NW China

The lacustrine organic-rich shale in the Permian Lucaogou (LCG) Formation of the Jimsar Sag, Junggar Basin, is one of the main shale oil plays in China. In this paper, geological and geochemical research techniques were employed to evaluate the geochemical variability of the lacustrine shale and the production of organic matter and its preservation conditions. The LCG Formation is characterized by its complex mineral compositions and a wide range of organic matter richness and quality. The presence of high proportions of β-carotane and C29 steranes, indicates that the organic matter mainly originated from phytoplankton and aquatic algal-bacterial organisms, especially cyanobacteria. This study found that the productivity of the Lower LCG Member (P2l1) was highest, and the Middle LCG Member (P2l2) was the lowest. During the deposition of the Lower LCG Member, the lake's bottom water was predominantly a reducing environment, and the degradation of organic matter was largely a result of bacterial sulfate reduction. During the deposition of the Middle and Upper LCG members, the lake's bottom water was mainly oxidizing, and the degradation of organic matter was likely to be caused by aerobic processes. Based on a comprehensive analysis of the origin and production of organic matter, as well as its depositional environment and preservation conditions, two organic matter accumulation models were proposed to explain the distribution of the organic-rich shale. In model A, the high influx of volcanic ash released nutrients and brought abundant sulfate into the water, the accumulation of organic matter was mainly controlled by the preservation of organic matter, which was mainly controlled by BSR. In the model B, the influx of volcanic ash was small, organic matter was mainly degraded by oxygen and the accumulation of organic matter is mainly determined by the production of organic matter.

Sedimentary origin of fine-grained rocks in the Permian Lucaogou Formation in the southern Junggar Basin: implications from grain size analysis

Sedimentary origin of fine-grained rocks in the Permian Lucaogou Formation in the southern Junggar Basin: implications from grain size analysis

Gas Generation Potential of Permian Oil-Prone Source Rocks and Natural Gas Exploration Potential in the Junggar Basin, NW China

The Junggar Basin, where twenty-seven oil fields and five gas fields have been discovered, is a typical “oil basin” with proven ratio of natural gas of 5.3%. The amount of natural gas from Permian source rocks has been found in the western margin of the basin, but no large-scale natural gas reservoir has been discovered. The key to natural gas exploration is whether Permian oil-prone source rocks have large gas generation potential. Based on the comprehensive analysis of geochemical features and hydrocarbon generation simulation experiments, it is proved that the gas generation intensity could meet the standard of medium to large gas-fields (20 × 108 m3/km2) at a depth of more than 6500 m. In the Penyijing and Shawan Sags, the burial depth of the Fengcheng Formation source rocks is between 8500 m and 10,000 m, respectively. It could be concluded that the Permian source rocks in the Penyijingxi and Shawan Sags have relative higher gas generation potential. In addition to high natural gas generation potential, two sets of effective reservoirs (wreathing volcanic rocks and secondary dissolution of sandy conglomerates) and thick caprocks with overpressure are developed in the most areas of Junggar Basin. Recently, natural gas reservoirs have been discovered and industrial natural gas had been obtained around the Penyijingxi Sag, Shawan Sags, and the Southern margin of the Junggar Basin. Our research results and natural gas exploration practice show that the Junggar Basin have relatively large natural gas exploration potential.

Middle-Late Jurassic chronology and source-to-sink system of the Sikeshu section in the southern margin of the Junggar Basin, Xinjiang

With the improvement of isotopic testing technology, high-precision dating methods such as SHRIMP or LA-ICP-MS of detrital zircon have been used to analyze and infer the formation age of sedimentary basins, the source of detrital materials, and the tectonic background of the formation and widely used. The LA-ICP-MS zircon U-Pb dating method was used to study the detrital zircon in the Middle-Late Jurassic sandstone in the Sikeshu section of the southern margin of the Junggar Basin, Xinjiang. The results show that the detrital zircon ages are mainly 270~447Ma,240~440Ma,245~432Ma, and 286~360Ma. There are also several ancient zircon ages, mainly 945~1080Ma. Combined with zircon mineralogical characteristics, CL images, Th/U ratio, sandstone petrographic characteristics, and regional chronological data, the primary provenance of the Middle-Late Jurassic sandstone is mainly from the Yilinghabilga Mountains in the North Tianshan, and Carboniferous-Permian volcanic rocks, pyroclastic rocks and Carboniferous granites exposed in the Borokonu Mountains of the Central Tianshan Mountains. By comparing the age changes between the four sampling points, the change process of the North Tianshan-Middle Tianshan source-sink system is obtained. From west to east, the upper Devonian glutamate, the Middle Devonian carbonate, and the large granite bodies of the Carboniferous series constituted the early watershed. From the middle to late period of the Toutunhe Formation to the Xishanyao Formation, from east to west, the Cambrian and Silurian carbonate rocks and the large granites and other rocks formed the late water line.

Depositional Model for the Early Triassic Braided River Delta and Controls on Oil Reservoirs in the Eastern Junggar Basin, Northwestern China

The Triassic Jiucaiyuan Formation is a vital oil and gas exploration target in the eastern part of the Junggar Basin. In this work, cores, thin sections, particle sizes, and conventional physical properties were analyzed in order to understand the sedimentary characteristics and depositional model of the Jiucaiyuan Formation in the Beisantai Uplift and to clarify the factors controlling reservoir development. The results demonstrate that the Jiucaiyuan Formation can be divided into seven lithofacies, namely massive bedding gravel, massive bedding sandstone, trough bedding sandstone, plane bedding sandstone, wavy bedding sandstone, parallel bedding siltstone, and massive bedding mudstone. Braided river delta facies dominate the Jiucaiyuan Formation. Nine main subtypes of facies were observed: flood plain, braided channel above lake level, natural levees above lake level, braided channel under lake level, interdistributary bays, natural levees under lake level, mouth bars, prodelta mud, and beach bar. The braided channel under lake level, mouth bar, and beach bar reservoirs exhibited the best physical properties, with average porosities of 16.54%, 19.83%, and 20.41%, respectively, and average permeabilities of 3.43 mD, 9.91 mD, and 12.98 mD, respectively. The physical properties of reservoirs in the study area are mainly controlled by sedimentation. Braided channels under lake level, mouth bars, and beach bars are favorable facies for the development of high-quality reservoirs. The results of this study are expected to serve as a theoretical basis for further exploration and development of oil and gas in the study area.

An aeromagnetic study of fault structures underneath the region across the Chinese Altai orogen, Junggar Basin, Tianshan orogen, and Tarim Basin

• We identified faults and volcanic suites in the Chinese Altai orogen, Junggar Basin, Tianshan orogen, and Tarim Basin regions. • The Junggar Basin has a basement composed of oceanic crustal material or continental-like material. • Mantle upwelling occurred during the Late Carboniferous–Cretaceous in the West Junggar orogenic belt . In this study, an aeromagnetic dataset is used to investigate the crustal structure in the region across the Chinese Altai orogen, Junggar Basin, Tianshan orogen, and Northern Tarim Basin, providing insights into the unclear nature of the basement of the Junggar Basin. The aeromagnetic data are for a region containing the Chinese Altai, Junggar Basin, Tianshan Mountains, and Tarim Basin. On the basis of magnetic anomalies, we identify several faults and volcanic suites in this region. According to the magnetic characteristics, gravity anomalies, and crustal thickness, we suggest that the Junggar Basin has a basement composed of oceanic crustal material or continental-like material. Mantle upwelling occurred in the West Junggar orogenic belt during the Late Carboniferous–Cretaceous. The faults we have identified provide useful insights into the tectonic development in the northwestern Central Asian Orogenic Belt.