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Carbonate rock from the Late Proterozoic to the Early Paleozoic is an important field of oil and gas exploration. The Sinian carbonate rock series in Tarim Basin are old, deep buried, with few drilling wells and various geological problems are unclear that restrict the exploration of deep carbonate rock. Based on the analysis of Sinian geological structure, by means of stratigraphic correlation and seismic prediction, the distribution of Sinian favorable source rocks, deep reservoir facies belts, and reservoir forming assemblages are studied to comb the exploration fields and favorable zones of Sinian in Tarim Basin. The findings reveal that slope-basin facies source rocks developed in Sinian. In the upper part of the Qigebulake Formation, high-quality dolomite reservoirs evolved, and mudstone from the Yuertus Formation at the foot of Cambrian can form favorable reservoir cap assemblage. The south slope of Tabei Uplift and the north slope of Tazhong Uplift are the most favorable exploration zones for Sinian dolomite, favorable exploration area of approximately 31,000 km2. The findings can provide a certain reference for the Sinian carbonate oil and gas exploration in the Tarim Basin.

The Lower Cambrian Xiaoerbulake Formation consist of thick dolostones which are high-quality hydrocarbon reservoir in the western Tarim Basin, but the origin of dolomite is still controversial, which lead to poor understanding to the origin of reservoir beds. By using the latest core data of Well XKD-1, we analyzed the petrology and geochemistry of the formation in order to clarify the genesis of dolomite. The geochemical analysis includes Sr, C, and O isotopes, and in-situ minor element and rare Earth element measurements for different types of dolomites by laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS). Four types of lithofacies are recognized in the Xiaoerbulake Formation based on different textures, which are laminated dolostone, thrombolite dolostone, bacteria-bonded dolostone, and grain dolostone. Two types of dolomites can be separated which are matrix dolomite (MD) and cement dolomite (CD). MD is the primary type of laminated and bacteria-bonded dolostone, and CD was developed mainly in grain dolostone and thrombolite dolostone. The δ13C and δ18O indicate that the grain dolostone and thrombolite dolostone have undergone more intensive diagenetic modification. On the contrary, the diagenetic modification of laminated and bacteria-bonded dolostone are relatively weak, which implies that the dolomitization of the latter two lithofacies occurs before burial stage. The 87Sr/86Sr ratio indicates that the corresponding fluid for dolomitization was seawater or marine-origin fluids. The MD was formed in the near-surface stage via the penecontemporaneous dolomitization of seawater or hyper-saline seawater. The dolomitization of CD occurred in the burial environment with the porosity was filled by marine-origin fluid, indicating a seepage-reflux dolomitization process. Both types of dolomites are partially affected by hydrothermal activities.

Among the world's 10 major gas producing countries, only the United States (USA), Russia and Iran have annual gas production of 250 × 109 m3 or more. China is expected to have gas output of 250 × 109 m3 in 2025. There are three advantages for the great development of natural gas industry in China. Firstly, the natural gas resources are rich and the proved rate is low and only 8.6%, so it has the resource advantage for faster development; Secondly, over the past 35 years, natural gas production continues to grow, with the growth advantage for faster development; Finally, since 2006, the remaining recoverable reserves of natural gas have been increasing year by year, showing the reserve advantage for faster development. In recent 10 years, China's annual natural gas production growth rate, remaining recoverable reserves and reserve-production ratio of natural gas support that China's annual gas production in 2025 will reach 250 × 109 m3. Suggestions for accelerating natural gas exploration and development during the 14th Five-Year Plan Period: (1) Opening new exploration and development fields of Carboniferous-Permian shale gas in the Ordos Basin; (2) Exploring three potential large gas districts with hidden coal measures in the northern Tianshan Piedown Depression, Qaidam Depression, and Xihu Sag; (3) Accelerating the development of seven large gas fields with proved reserves over 100 × 109 m3, such as Lingshui 17–2 Gas Field; (4) Increasing the drilling of gas wells and ultra-deep exploration wells.

Based on the observation of outcrops and cores, thin section identification, restoration of paleogeomorphology by residual thickness method, fine description of seismic facies, etc., the coupling relationships between the development patterns of various types of Cambrian platform margin mound-shoal complexes and paleogeomorphology in the Gucheng area of Tarim Basin have been examined. The Cambrian platform margin mound-shoal complex is divided into mound base, mound core, mound front, mound back and mound flat microfacies, which are composed of dolomites of seven textures with facies indication. The different paleogeomorphology before the deposition of mound-shoal complex in each period was reconstructed, and three types of mound-shoal complex sedimentary models corresponding to the paleogeomorphologies of four stages were established: namely, the first stage of gentle slope symmetric accretion type, the second stage of steep slope asymmetric accretion type and the third and fourth stages of steep slope asymmetric progradation type. Their microfacies are respectively characterized by “mound base - mound back + (small) mound core + mound front - mound flat” symmetric vertical accretion structure, “mound base - (large) mound core + mound front - mound flat” asymmetric vertical accretion structure, “mound base - (small) mound core + mound front - mound flat” asymmetric lateral progradation structure. With most developed favorable reservoir facies belt, the steep slope asymmetric accretion type mound-shoal complex with the characteristics of “large mound and large shoal” is the exploration target for oil and gas reservoir.

A series of investigations have been conducted concerning the study of traditional stable isotopes and rare gas stable isotopes in natural gas. However, little is known regarding non-traditional stable isotopes of mercury in natural gas, especially in the development and utilization of shale gas in recent years. In fact, the presence of mercury in natural gas (including shale gas) provides a basis for research on mercury isotopes. Mercury was extracted from shale gas at the Wufeng-Longmaxi Formation in the YS108 block of the Zhaotong National shale gas demonstration area in the Sichuan Basin by using an acid potassium permanganate solution, followed by the analysis of mercury content and stable isotope composition. The mercury content in the marine shale gas at the Wufeng-Longmaxi Formation ranged from 171 to 2,906 ng/m3, with an average of 1,551.08 ± 787.08 ng/m3 (n = 37, 1 SD). The Δ199Hg values of mercury stable isotopes range from 02‰ to 0.39‰, with an average of 22‰ ± 0.08‰ (n = 37, 1 SD); the δ202Hg values range from −1.68‰ to −0.04‰, with an average of −0.87‰ ± 0.31‰ (n = 37, 1 SD), which are significantly different from the Δ199Hg and δ202Hg information of coalbed gas, but similar to the Δ199Hg and δ202Hg information of terrestrial oil-type gas and the Δ199Hg in the main hydrocarbon-forming organic matter of lower organisms such as algae (t-test, p > 0.05). This indicates that terrestrial target strata with abundant algae or strata with positive Δ199Hg are the target strata for the exploration of terrestrial oil and gas.

Although the earliest animals might have evolved in certain “sweet spots” in the last 10 million years of Ediacaran (550–541 Ma), the Cambrian explosion requires sufficiently high levels of oxygen (O2) in the atmosphere and diverse habitable niches in the substantively oxygenated seafloor. However, previous studies indicate that the marine redox landscape was temporally oscillatory and spatially heterogeneous, suggesting the decoupling of atmospheric oxygenation and oceanic oxidation. The seawater sulfate concentration is controlled by both the atmospheric O2 level and the marine redox condition, with sulfide oxidation in continents as the major source, and sulfate reduction and pyrite burial as the major sink of seawater sulfate. It is thus important to quantify the sulfate concentration on the eve of the Cambrian explosion. In this study, we measured the pyrite contents and pyrite sulfur isotopes of black shale samples from the Yurtus Formation (Cambrian Series 2) in the Tarim Block, northwestern China. A numerical model is developed to calculate the seawater sulfate concentration using the pyrite content and pyrite sulfur isotope data. We first calibrate some key parameters based on observations from modern marine sediments. Then, the Monte Carlo simulation is applied to reduce the uncertainty raised by loosely confined parameters. Based on the geochemical data from both Tarim and Yangtze blocks, the modeling results indicate the seawater sulfate concentration of 8.9–14 mM, suggesting the seawater sulfate concentration was already 30–50% of the present level (28 mM). High seawater sulfate concentration might be attributed to the enhanced terrestrial sulfate input and widespread ocean oxygenation on the eve of the Cambrian explosion.

The Dabei gas field in the Kuqa Depression of the Tarim Basin is the most complex and deep continental condensate gas field in China. Comprehensive two-dimensional gas chromatography-time of flight mass spectrometer (GC×GC-TOFMS) analysis was conducted on five condensate oil samples from this field. The results show that the samples have n-alkane series in complete preservation and rich adamantanes. According to the methyladamantane index, the condensate oil is the product of the source rock with vitrinite reflectance (Ro) of 1.3%–1.6%. According to the gas maturity calculated through carbon isotope and vitrinite reflectance, the natural gas is corresponding to Ro of 1.3%–1.7%, reflecting that the natural gas and condensate oil are basically formed during the same period at the high maturity stage of source rock. The Dabei gas field has favorable geological conditions for hydrocarbon accumulation: thick salt rock in the Paleogene acts as a regional high-quality caprock directly overlying the high-quality sandstone reservoir of the Cretaceous, the coal source rocks have high hydrocarbon generation intensity and provide continuous oil and gas, and the subsalt thrust structures develop in rows with rich faults, providing migration pathways for oil and gas migration. These factors together controlled the formation of the Dabei gas field. Key words: condensate oil, molecular compound, adamantanes, comprehensive two-dimensional gas chromatography, Dabei gas field, Kuqa Depression, Tarim Basin

At present, deep and ultra-deep oil and gas have become the research and exploration hotspots. With little drilling data available, the geological understanding on deep formations is still in the exploratory stage, but most petroleum geologists have universally acknowledged that the deeply-buried strata of Chinese marine craton basins are equipped with the conditions for abundant oil and gas resources. A series of discoveries have been made in the Ordovician and Cambrian strata. For Precambrian strata, besides breakthroughs in the Sichuan Basin, a lot of research or drilling work has been initiated in other basins. In the Tarim Basin, the current burial depth of the Lower Paleozoic and the Precambrian mainly ranges from 5000 to 12000 m. This is attributed to rapid subsidence and deposition since the Neogene. A large number of exploration discoveries have been made, and commercial productivity projects have been constructed at the depth less than 8000 m. Strata more than 8000 m deep will be a significant major prospecting exploration field in the future. The analyses of hydrocarbon accumulation conditions of the ultra-deep layers of the Tarim Basin provide theoretical guidance for ultra-deep oil and gas exploration. This research is based on source rocks in the Cambrian, Sinian, and Nanhua System, formation and preservation of ultra-deep carbonate reservoirs, phase of petroleum and accumulation assemblages in ultra-deep strata, the exploration fields deeper than 8000 m were also evaluated to sort out the most favorable areas and, future exploration focuses on the Ordovician, Cambrian, and Sinian strata are pointed out. Keywords: Ultra-deep, Neoproterozoic, Phase of petroleum, Cambrian, Craton basin, Tarim Basin

In order to have a better understanding of the geochemical characteristics of gases from deep depths, gases from the clastic sandstone reservoirs in the Dabei and Keshen gas fields in the Kuqa depression, Tarim Basin, and gases from the marine carbonate reservoirs (Ordovician and Cambrian) in the craton area of Tarim Basin and Sichuan Basin (Yuanba, Longgang, Puguang gas fields) are investigated based on the molecular composition, stable carbon and hydrogen isotopes. Deep gas, either from the clastic sandstone reservoirs or from the marine carbonate reservoirs, is dominated by alkane gas. Gases from Kuqa depression and Sichuan Basin are dry gas, with high gas dryness coefficient, 0.976 and 0.999, respectively. Deep gas from the craton area in Tarim Basin includes both dry and wet gases. N2 and CO2 are the common non-hydrocarbon components in the deep gas. Gases from the continental sandstone reservoirs have no H2S, while gases from the marine carbonate reservoirs often have H2S. The relatively high δ13C2 value in the Kuqa depression indicates the gas was generated from humic type III kerogen, while the relatively low δ13C2 value in the craton area of Tarim Basin indicates most of the gas was generated from the marine sapropelic organic matter. Deep gas in Sichuan Basin, which has medium δ13C2 value, was generated from both humic type III and sapropelic type II organic matter. Carbon isotopic anomaly such as partial carbon isotopic reversal or relatively heavy carbon isotope is common in the deep gas, which is caused by secondary alteration. Gases from the Dabei gas field have a mean δ2H1 value of –156‰, while gases from the craton area of Tarim Basin, and Yuanba and Puguang gas fields in Sichuan Basin have relatively heavier δ2H1 value, i.e., average at −130 and −122‰, respectively. The abnormally heavier δ2H1 value in Dabei gas field is due to the high thermal maturity and possible saline depositional environment of the source rocks. This study performed a comprehensive comparison of the geochemical characteristics of the deep gases with different origins, which may provide a hint for future exploration of deep gas in the world.

Pollution generated by livestock and poultry rearing is an important environmental issue, and gas emissions during animal production are continuously increasing. A digital rearing chamber inspection system was designed in the present study in order to examine the waste tea litter’s impact on the growth performance and harmful gas emissions, such as ammonia (NH3) and carbon dioxide (CO2), during broiler rearing. Broilers were raised without litter and with waste tea litter. According to the results, broiler growth showed little difference between the two groups during the experimental period, and it was concluded that waste tea litter had no impact on broiler growth. Meanwhile, the gas emissions of the waste tea-litter group were lower than the non-bedding-materials group. In detail, the average concentrations of NH3 and CO2 of the non-bedding-materials group were 9.33 ± 3.65 ppm and 797 ± 107 ppm, respectively; while these concentrations in the waste-tea-litter group were 1.01 ± 0.35 ppm and 713 ± 69 ppm, respectively. According to the analysis of the litter properties, it was suggested that waste tea litter can reduce the moisture content in litter, and affect microbial and urease activity due to its low carbon nitrogen ratio (C/N), weak acid, and porous structure characteristics. In conclusion, this study showed the potential of waste tea litter in NH3 and CO2 emission reduction during broiler rearing.

Due to deep burial of Precambrian in Tarim Basin, no breakthrough in the hydrocarbon exploration has been achieved from these strata, and development of high-quality source rocks is also uncertain. More than 30 exploratory wells have been drilled in the southwest Tarim Basin and the pediment region of Kunlun Mountains with a total area of more than 100 × 103 km2. Though some marine oil/gas fields such as Hetianhe, Bashituopu, Yubei and Luosi 2 have been discovered, the Cambrian or Ordovician source rocks have not been drilled, and hydrocarbon source still remain controversial. Recently, a set of thick black shales and mudstones has been found in the southwest Tarim Basin. The total thickness of mudstones is more than 140 m, and the total organic carbon mainly ranges from 0.6% to 1.9% with an average of 1.0%. Tmax is from 490 °C to 520 °C, equivalent to Ro from 1.99% to 2.99%. Pyrites are very rich in mudstone. According to stratigraphic contact relationship and isotopic chronology, this mudstone may have the age of more than 517 Ma, and is tentatively named as the “Western Kunlun black rock series”. Through the plate tectonic analysis, this set of thick black mudstones is possibly distributed widely in the southwest Tarim Basin, and its formation may be controlled by the aulacogen. This set of black mudstones may be an important source rocks in the southwest Tarim Basin, which suggest that the Precambrian-Cambrian strata in Tarim Basin has geological conditions for hydrocarbon accumulations. This discovery of the black thick mudstones in the southwest Tarim Basin will promote hydrocarbon exploration in the deep and ultra-deep strata of the Tarim Basin. Keywords: The black rock series, High-quality source rocks, Precambrian, TOC, Tmax, Southwest tarim basin

According to the aeromagnetic, seismic, and geological data, the surface structure, sedimentation, and distribution characteristics as well as the deep dynamic mechanism of the north-south differentiated Neoproterozoic rift basins were well investigated to reveal the tectonic evolution and its control on the distribution of the Early Cambrian sedimentary basin and source rocks in the Tarim Basin. The rift basin in the southern Tarim was a product of superplume activities during the early breakup period of the Rodinia supercontinent. It initiated in the Early Cryogenian (about 780 Ma) and appeared as NE-direction aulacogens extending into the Tarim Basin. The rift basin in the northern Tarim was a back-arc rift basin derived from the subduction of Pan-Rodinian oceanic plate, which initiated in the Late Cryogenian (about 740 Ma) and occurred as a nearly EW-direction narrow band across the Tarim Basin. The northern Tarim back-arc rift basin had similar formation and evolution process to the Late Mesozoic-Cenozoic back-arc rift basins in East Asia, both showing an oceanward migration; however, the Tarim rift basin finally evolved from the fault-depression basins into passive continental margin. The Neoproterozoic rift basins controlled not only the distribution of source rocks in the syn-rift period but also the development of Early Cambrian sedimentary basin. Nearly EW-distributed syn-rift (Cryogenian to Ediacaran) and post-rift (Lower Cambrian Yurtusi period) source rocks were likely to develop between the present Tabei uplift and central uplift belt. Keywords: Neoproterozoic, Rift, Dynamic mechanism, Subduction, Mantle plume, Source rock, Tarim basin

As the largest oil-and-gas-bearing basin in China, the Tarim Basin contains rich oil and gas resources buried deep underground. In recent years, large oil fields have been discovered in the Halahatang area of the northern Tarim Basin. The reservoir is buried 6000–7300 m underground. This reservoir is dominated by the Ordovician carbonate rocks, and the crude oil is mainly heavy oil. As a crude oil-associated gas, the natural gas generally contains hydrogen sulfide (H2S). The heavy oil in this region is the deepest buried heavy oil found in the world. H2S is also associated with the deepest buried natural gas. The burial, preservation and degree of biodegradation of a paleo-reservoir can be used to predict the distribution of H2S. According to research findings, there is a clear planar distribution pattern of H2S content: high in the east and north, and low in the west and south. We compared the physical properties of crude oil and the analysis of the composition of natural gas and isotopes, biomarker compounds of crude oil and groundwater. We find that the content of H2S in natural gas bears some relation to the physical properties and degree of biodegradation of crude oil. Crude oil density, sulfur content, colloid, and asphaltene have positive correlations with H2S content in natural gas. The formation of H2S is controlled by the degradation and densification of crude oil. Crude oil densification can lead to an increase of the sulfur content. The rise in the temperature of the reservoir resulting from the depth of burial causes the thermal decomposition of sulfur compounds to produce H2S. The generation of H2S by the thermal decomposition of sulfur compounds is confirmed by data on sulfur isotopes. The distribution of H2S can then be predicted based on the burial conditions of the paleo-reservoir and the degree of biodegradation. In the south Rewapu of the Halahatang area, the thick cap rock of the Ordovician oil reservoir was preserved well in the late Hercynian Period, without undergoing biodegradation. The oil is mainly normal oil and light oil. Sulfur content in the crude oil is quite low, making it impossible to generate a large amount of H2S in the later stages of deep burial.

Based on outcrops of the whole basin, drilling and seismic data, this paper makes a systematic analysis of Neoproterozoic basin stratigraphic distribution and tectonic evolution characteristics in Tarim. Under the control of the aggregation and breakup of Rodinia supercontinent, the extensional sedimentary basin formed with North-South differences in the Neoproterozoic, separated by the middle ancient land. There is a sedimentary basin in the north, east-west banded, with two thickness centers, Aksu region in northwest and Manjiaer-Kuruketage region in northeast and maximum thickness about 2 500−3 500 m. There are two sedimentary basins in the south, north-east banded, with two thickness centers, Yecheng and Hetian with maximum thickness about 1 500−2 000 m. The evolution of the basin can be divided into two stages, rift in Nanhuan (Cryogenian) and depression in Sinian (Ediacaran), the latter stage deposits larger range but with thinner thickness of strata. Its main rock types contain volcanic rock, clastic rock, moraine rock and carbonate rock. The distribution of source rock during Early Cambrian period is mainly controlled by the development characteristics of the Neoproterozoic sedimentary basin. Key words: Tarim basin, Neoproterozoic, Nanhua, Sinian, Early Cambrian, source rock

The Upper Paleozoic strata of the Tarim Basin have abundant resources of marine oil and gas. In the Tahe area, Halahatang area, and Tazhong area of the basin, many large-scale oilfields have been found. These oilfields have a confirmed oil and gas reserves worth more than 2.5 billion tons and have completed the annual output of more than 14 million tons of marine oil and gas equivalent. The belief that the only main hydrocarbon source rocks are of the Cambrian or Ordovician is still controversial. Chemists have made significant progress and have effectively lead the oil and gas exploration in Tarim Basin. Due to the complexity of the basin and the limitation of samples, the research work, and fine contrast is restricted. In this article, we investigated the Cambrian strata outcrop of Tarim Basin in detail. By analyzing a lot of outcrops, high-quality hydrocarbon source rocks of Yuertusi Formation have been found in more than 10 outcrop points in Aksu region. The source rocks' lithology is black shale with total organic carbon (TOC) content that ranges between 2% and 16%. Total organic carbon (TOC) of the black shale layer could be as much as 4%–16%, especially in the outcrops of the Yutixi and Shiairike. This by far is the best marine hydrocarbon source rock that was found in China. The source rocks were distributed consistently in the Aksu region, the thickness of which is about 10–15 m. It was formed in a sedimentary environment of a middle gentle slope to a low gentle slope. Organic matter enrichment is controlled by the upwelling currents. The thick strata of dolostone that developed in the Xiaoerblak Formation are considered to be good reservoirs of the beach and microbial reef in the upper strata of Yuertusi Formation. No hydrocarbon source rocks have been found in the outcrop of Xiaoerblak Formation. The thick strata of gyprock and mudstone development are a set of satisfactory cap layer in the Lower Cambrian. This hydrocarbon accumulation combination has great exploration potential.

The onshore exploration realm has been continuously expanded to (ultra-) deep oil and gas recently in China. New comprehension and significant breakthroughs have been made in understanding generation and preservation conditions, reservoirs formation mechanisms, exploration potential, petroleum resources assessments, and exploration engineering technology of deep oil and gas. Deep oil and gas reservoirs include clastic, carbonate and volcanic settings. The temperature of deep oil can be up to 295 °C. Long term shallow burial and rapid deep burial at late stages help preserve the porosity in deep clastic rocks, and dissolution and fracturing effects improve their reservoir properties. Affected by faulting, hydrothermal karst processes, dolomitization and early oil and gas injection, carbonate rocks have good reservoir properties even at depths of 8 000 m. Controlled by tectonism, volcanism, diagenesis and diagenetic reconstruction during supergene and burial stages, primary and secondary weathering types of reservoirs develop deep volcanic reservoirs. Deep oil and gas resources in China are distributed mainly within three main practical areas of carbonate, clastic and volcanic areas. Dominated by gas, some of the more productive areas include the Tarim, Ordos, Sichuan, Junggar, Songliao, Santanghu and Bohai Bay basins. Deep oil and gas exploration in China has entered an age of breakthrough and discovery. Relevant engineering technology, such as ultra deep well drilling and ultra high temperature drilling fluid techniques have facilitated the ability to find (ultra-) deep oil and gas. Key words: deep oil and gas, reservoir formation mechanism, resources potential, exploration engineering technology

To figure out the oil and gas distribution pattern in the Tarim Basin, the adjustment and reformation of oil and gas reservoirs under the background of late Himalayan Orogeny are analyzed. Strongly affected by the tectonic movement, the oil and gas reservoirs in the Tarim Basin experienced secondary actions in physical adjustment and chemical alteration: on the one hand, during the course of physical adjustment, reversed strata caused the early-formed oil to seep vertically and to migrate laterally along the sandstone in large scale with long distance; on the other hand, in the process of chemical alteration, the deposition of massive strata accelerated the thermal evolution of organic matter, generating large amounts of cracking gas, which went into the pre-existing reservoirs and led to big change in oil and gas properties and the coexistence of heavy oil, light oil, waxy oil and condensate gas in the same area. The physical adjustment and chemical reformation of oil and gas reservoirs in late Himalayan period resulted in the lateral differential distribution of oil and gas in large area and multiple vertical oil-bearing layers with complex and diverse oil and gas properties. Key words: hydrocarbon reservoir adjustment, chemical alteration, strata reversal, biodegradation, oil cracking, late Himalayan period

The Cryogenian (ca. 717–635 Ma) snowball Earth glaciations ended with the precipitation of “cap” carbonate successions with negative carbon isotope (δ13Ccarb) values, which have been explained by the addition of various 13C-depleted carbon sources in the deglacial process. These arguments assumed that marine dissolved inorganic carbon (DIC) was enriched in 13C in the synglacial ocean. However, this assumption has not yet been tested, because the synglacial ocean chemistry is unknown. In this study, we carried out detailed analyses of the petrology, carbonate carbon (δ13Ccarb) and oxygen (δ18Ocarb) isotopes, organic carbon (δ13Corg) isotopes, major and minor elemental compositions (Ca, Mg, Mn, Fe, Sr), and iron speciation (total Fe, highly reactive Fe, pyrite Fe) of the carbonate layers (also called synglacial carbonate layers) from the Nantuo Formation (ca. 650–635 Ma) on the Yangtze block, South China. Petrographic observations indicated that the synglacial carbonate comprises dolomicrite, mud-crystal powder dolomite, lime dolomite, and dolomitic limestone, supporting an authigenic carbonate origin, and thus, it potentially recorded the ocean chemistry during the Marinoan ice age. The synglacial carbonate is characterized by extreme Mn enrichment, low Fe/Mn ratios, and low δ13Ccarb (−7‰) values. High Mn contents and low Fe/Mn ratios imply marine redox conditions favoring Mn2+ accumulation and Fe2+ oxidation, while low δ13Ccarb values might be attributed to CO2 degassing of submarine volcanoes as well as low primary burial during the glaciation. Since the δ13CDIC value of the synglacial ocean was lower than the δ13Ccarb values of most cap carbonates, we infer the addition of 13C-enriched DIC or removal of 12C during cap carbonate precipitation, such as through carbonate weathering or organic carbon burial. These findings provide new insights into the nature of Cryogenian glaciation, the origin of cap carbonates, and the aftermath of global glaciation [ABSTRACT FROM AUTHOR]

Understanding the key timings related to petroleum evolution is crucial for optimizing exploration targets and assessing oil/gas resources, attract petroleum geologists’ attention worldwide. Recently, hydrocarbon (oil and bitumen) Re–Os isotope dating has been innovatively applied to constrain the timing related to oil/gas generation, however, the resulting Re–Os isochron ages can be complex and challenging to interpret. This study utilizes various geochemical and geochronological data from Sinian to Cambrian natural gas reservoirs in the Sichuan Basin to reconstruct the hydrocarbon evolution process and discuss the significance of different bitumen Re–Os dating results. The gas accumulation in the SinianCambrian reservoirs experienced four stages of evolution: (1) initial oil generation during the Ordovician to Silurian periods, (2) secondary oil generation during the Triassic period, (3) gas generation through thermal cracking of liquid oil from the Jurassic to Cretaceous periods, and (4) gas reservoir redistribution since the late Cretaceous. The Re–Os dates (ca. 485 Ma) of low maturity and biodegraded bitumen from the western Sichuan Basin record the oil generation during the Ordovician before the Caledonian tectonic event. The Re–Os dates (ca.184–128 Ma) of highly mature bitumen associated with MVT Pb–Zn deposits in northern Sichuan Basin provide insights into both liquid oil-cracking and thermochemical sulfate reduction (TSR) processes. The complex Re–Os dates (ca.414 Ma, ca.154 Ma) of highly mature bitumen from the central Sichuan Basin may represent different periods related to either oil or gas generation. Future studies should explore the genetic type, maturity, thermal cracking, or TSR degrees of bitumen to better understand the significance of Re–Os dates. [ABSTRACT FROM AUTHOR]

The 8.2 ka event has been extensively investigated as a remarkable single event, but rarely considered as a part of multi-centennial climatic evolution. Here, we present absolutely dated speleothem multi-proxy records spanning 9.0-7.9 ka BP from Beijing in North China, near the northern limit of the East Asian summer monsoon (EASM) and thus sensitive to climate change, to provide evidence for the intensified multi-decadal climatic oscillations since 8.5 ka BP. Three extreme excursions characterized by inter-decadal consecutive δ18O excursions exceeding ±1s are identified from 8.5 ka BP in our speleothem record. The former two are characterized by enriched 18O at ~8.40 and 8.20 ka BP, respectively, suggesting a prolonged arid event which is supported by the positive trend in δ13C values, increased trace element ratios, and lower growth rate. Following the 8.2 ka event, an excessive rebound immediately emerges in our δ18O and trace element records but moderate in the δ13C, probably suggesting pluvial conditions and nonlinear response of the local ecosystem. Following two similar severe droughts at 8.40 and 8.20 ka BP, the different behavior of δ13C suggests the recovering degree of resilient ecosystem responding to different rebounded rainfall intensity. A comparison with other high-resolution records suggests that the two droughts-one pluvial patterns between 8.5 and 8.0 ka BP are of global significance instead of a regional phenomenon, which is causally linked to the slowdown and acceleration of the Atlantic Meridional Overturning Circulation that was further dominated by the freshwater injections in the North Atlantic. [ABSTRACT FROM AUTHOR]