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Slab material transfer processes in continental arcs can be challenging to decipher because magmas are often characterized by significant contributions from continental material. In this study, we identified a Prototethyan continental arc (419–418 Ma) that is now located in the Dazhonghe area of the southeast Tibetan Plateau, which, based on Sr-Nd-Hf-O-Si isotope relationships, implies no detectable continental material contributions. The Dazhonghe arc rocks display much lower δ30Si values than modern arc rocks and average mantle; this is best explained by subduction of sponge-rich marine sediments, which are thought to have been the dominant marine organisms during the Neoproterozoic and early Paleozoic. Our mixing calculations reveal that only bulk mixing among sponge-rich sediments, altered oceanic crust (AOC), and the depleted mantle would be capable of accounting for all the Sr-Nd-Hf-O-Si isotope compositions. This finding implies that the Dazhonghe arc magmas were generated by melting of a mélange that formed at the slab-mantle interface. The Dazhonghe continental arc is the first for which mélange melting has been confirmed.

This paper presents the first application of U-Pb dating to resolve the geological age of the Late Miocene mammalian fauna. Five fossil beds containing late Miocene mammalian fauna can be found in northern China, which include fossil specimens of Hipparion chiai, is most fixed time indicator fossil. However, the geological age of the fossil belt is still unresolved. Absolute dating of sedimentary rocks and fossils from the late Miocene is still rare, mainly due to the difficulties arising from suitable absolute dating technique and sample diagenetic changes. Biological Apatite (carbonated Hydroxyapatite) in the teeth fossils of Hipparion chiai contain Uranium, high μ value (the initial value of 238U/204Pbi), limited Th content and remain relatively unchanged due to their resistance to diagenetic alterations. Here, we first derived six fossil teeth of Hipparion chiai were sampled from the Wangdafuliang section in Fugu, in the Shaanxi Province, and were dated using the U/Pb method to obtain an absolute age. The U-Pb dates obtained from the six fossil teeth of Hipparion chiai varied, ranging from 6.87±0.13 Ma to 7.71±0.39 Ma (2 s), with an average of 7.26 Ma. This result provides a new basis for determining the age of the Hipparion chiai-Dinocrocuta gigantean-Hezhengia-Shaanxispira standard fossil belt (index fossil assemblage) from the Late Miocene in northern China. The belt is probably 7.26 Ma, rather than previous estimates of 10–9 Ma. The absolute dating of fossils, in turn, bring about a new revolution in Biostratigraphy and establish the geochronology of sedimentary sequences at sub-millennial timescales, especially those early Cenozoic stratigraphy that is absent of an suitable absolute dating technique.

The Tarim basin not only is one of the main targets for hydrocarbon exploration in China, but also hosts the Early Permian LIP, thereby providing an ideal laboratory to investigate how the LIP eruptions interact with the petroleum system in the volcanic-affected basins. Six major second-order domes were identified in the first-order dome that involves the entire Tarim LIP, based on seismic probing and lithofacies and stratigraphic observations in boreholes and the stratigraphic sections. These second-order domes are characterized by abundant Permian basaltic dykes and volcanic craters, indicative of the origin from the LIP eruption. They also are the sites of the almost all Paleozoic oil and gas reservoirs in the Tarim basin. Dating on authigenic illites collected from 20 Silurian bituminous and oil-saturated sandstone samples in the Tarim basin, along with literature data, indicates that hydrocarbon charge and emplacement in the Paleozoic reservoirs prevalently occurred during 300–255 Ma, approximately concurrent with the eruption of the Tarim LIP lavas (300–262 Ma). Therefore, we propose that the LIP eruption not only created the second-order domes that provided space for the oil and gas charge but also triggered the rapid release of hydrocarbon through the volcanic vents, thereby controlling the formation of Paleozoic oil and gas fields in the Tarim basin.

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.

Land-use change influences the fate of nutrient elements, including iron (Fe), and then threaten soil security. In this study, Fe forms and stable isotope composition (δ

The Permian-Triassic mass extinction severely depleted biodiversity, primarily observed in the body fossil of well-skeletonized animals. Understanding how whole ecosystems were affected and rebuilt following the crisis requires evidence from both skeletonized and soft-bodied animals; the best comprehensive information on soft-bodied animals comes from ichnofossils. We analyzed abundant trace fossils from 26 sections across the Permian-Triassic boundary in China and report key metrics of ichnodiversity, ichnodisparity, ecospace utilization, and ecosystem engineering. We find that infaunal ecologic structure was well established in the early Smithian. Decoupling of diversity between deposit feeders and suspension feeders in carbonate ramp-platform settings implies that an effect of trophic group amensalism could have delayed the recovery of nonmotile, suspension-feeding epifauna in the Early Triassic. This differential reaction of infaunal ecosystems to variable environmental controls thus played a substantial but heretofore little appreciated evolutionary and ecologic role in the overall recovery in the hot Early Triassic ocean.

Shale gas wastewater (SGW) disposal is a major challenge in the areas in central China due to its increasing volume associated with intensification of shale gas exploration and its high levels of contaminants. In the Fuling shale gas field of Sichuan Basin, a small amount of SGW originated from the flowback and produced water (FPW) is treated and then discharged to a local stream. This study investigated the inorganic water geochemistry and Sr isotopic composition of the FPW in Fuling shale gas field, the SGW effluent that is generated in the treatment facility, and the quality of a local river after the disposal of treated SGW. The data generated in this study reveals that FPW generate after several years of shale gas operation maintain the original geochemical fingerprints detected in early stages of FPW generation, and consistent with the FPW composition detected in other shale gas fields in Sichuan Basin. We show that reuse of saline FPW for hydraulic fracturing can generate an inverse salinity trend, where the salinity of FPW decreases with time, reflecting the increase of the contribution of formation water with lower salinity. The treatment of the FPW results in ~40 % reduction of the salts by dilution with freshwater and selective (80-90 %) removal of some of the inorganic contaminants. The original geochemical fingerprints of the FPW from Fuling shale gas field was not modified during FPW treatment, reinforcing the applicability of these tracers for detecting SGW in the environment. Discharge of treated SGW effluent to a local river causes a major 200-fold dilution and reduction of all contaminants levels below drinking water and ecological standards. Overall, this study emphasizes the importance of water quality monitoring of treated SGW and the overall measures needed to protect public health and the environment in areas of shale gas development.

The widely developed black shales deposited during the early Cambrian recorded paleoenvironmental information about coeval seawater. Numerous studies have been conducted on these shales to reconstruct the paleomarine environment during this time period. However, most research has been conducted on stratigraphic sections in South China, and equivalent studies of sections from other cratons are relatively rare. Here, we report Mo isotopic compositions as well as redox-sensitive trace-element and iron (Fe) speciation data for black shales of the Lower Cambrian Yuertusi Formation from the Tarim block (i.e., a small craton). The Fe speciation data show high FeHR/FeT and Fepy/FeHR ratios, indicating roughly sustained euxinic bottom-water conditions during their deposition. Based on Mo isotopic compositions (δ98/95Mo), we further classified the euxinic black shales into two intervals: a lower interval (0–21.3 m) and an upper interval (21.3–32.3 m). The lower interval is characterized by variable Mo isotopic compositions (−2.12‰ to +0.57‰, mean = –0.52‰ ± 0.72‰), with an obvious negative excursion in its middle portion. The overlying upper interval has relatively heavy δ98/95Mo values up to +1.42‰ (mean = +0.62‰ ± 0.37‰). We ascribe δ98/95Mo differences in the lower and upper intervals to inadequate aqueous H2S concentrations for quantitative thiomolybdate formation under euxinic conditions. The most negative Mo isotope excursion may have been caused by upwelling hydrothermal inputs during a transgression, consistent with significantly elevated total organic carbon (TOC) contents, Mo and U enrichments, and Fe supply. Relatively positive δ98/95Mo values in the upper interval have roughly similar variations with other coeval sections, indicating such variations were common for early Cambrian euxinic deposits, and they were most likely caused by local differences in [H2S]aq. Compilation of Mo isotope data from the early Cambrian and earlier times further indicates relatively oxygenated seawater, especially the deep-marine areas during the early Cambrian before reaching a state like modern seawater.

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.

Large quantities of Triassic solid asphaltite were discovered in the Guangyuan area, northwest Sichuan. The asphaltite is formed in layers with a vertical thickness between 0.3 and 2.8 m and is stably distributed with intrusive contact with surrounding rocks. This study aims on the genesis and distribution of asphaltite through trace element, biomarker, and Re-Os isotope analyses. Trace element analysis shows the enrichment of V and Cr in the asphaltite, indicating that it is derived from relatively deep hydrocarbon sources. The carbon isotope and biomarker results suggest that the asphaltite originates from Cambrian paleo reservoir. The Re-Os isotope analysis determines a formation age of 220 ± 6 Ma, which corresponds to the late Triassic, indicating the cracking of paleo reservoirs in late Triassic. Therefore, the origin of asphaltite is epigenetic-reservoir asphaltite. The generation of oil from Cambrian source rocks began at the end of Silurian and ended after Caledonian orogeny. At the end of Permian, the fracture system was well developed due to the influence of the Hercynian movement, which provided favorable conditions for the migration of Cambrian oil. By the end of Triassic, hydrocarbons generated from Cambrian source rocks were mainly distributed in fractures and reservoirs, thus forming paleo oil reservoirs. Afterward, the paleo reservoirs were adjusted to the surface or near the surface during the Indosinian movement and thus have cracked into asphaltite. The distribution of asphaltite is closely related to the tectonic activities, and the asphaltite is preferentially stored in the anticline axes, fissures, and some interlayer fracture zones.

Contrasting models for internal versus external locations of the South China Craton (SCC) in the supercontinent Rodinia and associated mantle plume or ocean subduction dominated tectonic processes can be resolved by detrital zircon U-Pb dating and Lu-Hf isotopic analyses on the Cryogenian Nanhua Supergroup in the central SCC. Our results show that samples from the lower Liantuo, Tiesi’ao, and Datangpo formations of the Nanhua Supergroup show three age peaks at 2.50 Ga, 2.05 Ga, and 0.85 Ga, and those of the upper Nantuo Formation yield four peaks at 2.50 Ga, 2.05 Ga, 0.85 Ga, and 0.65 Ga. The Archean and Paleoproterozoic (1.80–2.10 Ga) zircons have εHf(t) values of −16.3 to +4.7 and −23.0 to +4.2, and may be sourced from the Kongling and Douling complexes and Paleoproterozoic intrusions in the northern Yangtze Block, respectively. Early Neoproterozoic (0.70–0.96 Ga) zircon grains show variable εHf(t) values of −20.0 to +15.0. In combination with the absence of Mesoproterozoic detrital zircons in the Nanhua Supergroup, huge volumes of Neoproterozoic granitic intrusions in the northern Yangtze Block are the potential sources for the 0.70–0.96 Ga detrital zircons. Only the siltstone of the Nantuo Formation has late Neoproterozoic (0.63–0.69 Ga) detrital zircons with high and positive εHf(t) values (+7.9 to +9.4). Several granitoid intrusions (0.63–0.68 Ga) in the Wudang and Ankang uplift of the South Qinling belt in the northern Yangtze Block provide the late Neoproterozoic detrital zircons of the Nantuo Formation. These provenance analyses of the Nanhua Supergroup indicate an interior source from the SCC, rather than an exterior source from the Laurentia and Australia cratons. The Neoproterozoic rift basins and magmatic rocks in the SCC were produced by secular episodic subductions and back-arc extensions, rather than a Neoproterozoic super-mantle plume. The SCC occupied a peripheral position adjacent to northern India in Rodinia during the Neoproterozoic. These conclusions will promote our understanding of genetic mechanism and distribution prediction of the several Cryogenian–Cambrian black-shale layers and excellent source rocks in the SCC.

Deep carbonate strata in the Sichuan Basin in China mainly produce natural gas of high maturity. The discovery of uncommon condensate oil in the Zhongba gas field is of particular research interest...

Natural gases in deep strata (> 7000 m) in the Kuqa Depression of the Tarim Basin are abundant and well characterized, but oils and condensates are rare and poorly understood. We obtained a sample ...

Late Neoproterozoic extensive rifting in Tarim has been intensely debated regarding an intracontinental or a back-arc environment, which forms a key aspect for elucidating the Precambrian basement architecture and evolution of the Tarim craton. Recently, a deep well called Tarim Geological Survey Well (X1) was drilled from the northwest Tarim basin. Sixty-six samples were collected from the Sugetbrak Formation of the X1 well, including 6 sandstone samples, 29 mudstone samples and 31 basalt samples, for integrated geochemical, geochronological, and Sr–Nd–Hf isotopic analyses. The results indicate that the basalts geochemically show distinct affinity with ocean-island basalts, characterized by enrichments in light rare-earth elements (REEs) and no depletions in Nb and Ta and indicating an intracontinental rifting environment. The presence of 572-Ma zircon in the Sugetbrak basalts reveal the rifting mainly developed in an interval of 541–572 Ma. Geochemical and petrographic data show that the coeval basaltic tuffs or clasts contributed 5–20% to the deposition of the Sugetbrak Formation. The zircon age cluster between 1.8 and 2.0 Ga and abundant Paleoproterozoic detrital zircons with ultrahigh-temperature (UHT) granulate REE signature in the Sugetbrak sandstones indicate a Paleoproterozoic orogenic event occurred in the Tarim craton that could be related to the assembly of the Columbia supercontinent. In contrast, the Neoproterozoic zircons from the Sugetbrak sandstones display positive eHf(t) values, and some have hydrothermal alteration REE signature, indicating Tarim could be a locus for early mantle plume activities that broke the Rodina supercontinent.

The Neoproterozoic Earth witnessed major global glaciation events with significant impact on paleoclimate and life evolution. The Tarim Craton in China preserves the records of four glaciation events during the Neoproterozoic which were correlated with the global glaciations, the nature and impact of these with respect to Neoproterozoic paleoclimatic–paleogeographic reconstructions remain unresolved. Here we report the discovery of a suite of source rocks from northeastern Tarim in which the strata formed during 655–635 Ma, corresponding to the interglacial period between the Sturtian and Marinoan diamictites. These source rocks are dominated by black shales and mudstones of up to 300 m thickness, and are characterized by high content of organic matter with TOC (total organic carbon) of 0.46%–3.5% (average 1.64%), vitrinite reflectance Ro of 1.28%–1.60%, and kerogen carbon isotope δ13C value between −28.58‰ and −31.89‰. Biomarker compounds indicate that the organic matter in these saprolite source rocks are made up of microorganisms such as algae and bacteria. The Pr and Ph values indicate a weak reducing–oxidizing environment, and most values of CIA (Chemical Index of Alteration) are >68, suggesting an interglacial temperate paleoclimate. The La/Th–Hf and Co/Th–La/Sc relationship suggests that the provenance of these rocks is mainly mixed felsic/mafic rocks. In the Tarim basin, these source rocks comprise an area of up to 90,000 km2 within Cryogenian rifts as inferred from seismic reflection profiles. Based on zircon U Pb ages of volcanic rocks underlying the shale units, it is inferred the source rock formed during the temperate Sturtian glaciation events with subsequent extensive biotic recovery and high productivity.

The newly discovered Halahatang oil field in the northern Tarim Basin has a potential resource of more than 70 billion bbl of oil. Oil organic geochemical data from the Halahatang oil field indicate that the oils are of moderate maturity, biodegraded, and represent one oil family, derived from the same Paleozoic marine source. Modeling of coeval aqueous and hydrocarbon-bearing inclusion data provide fluid trapping temperatures and pressures of 100°C to 110°C and approximately 39 to 59 MPa (∼5656–8557 psi), respectively. The fluid inclusion data coupled with the previous basin model studies suggest a single prolonged oil migration event during the Permian. The Re–Os isotope data of the oil yields an early Permian Re–Os age of 285 ± 48 Ma. The age agrees with the timing of maturation of the Paleozoic source via burial history modeling but is slightly older (∼5–55 m.y.) than the oil migration and accumulation timing implied by the basin modeling coupled with fluid inclusion analysis and the published reservoir illite K–Ar dates. Thus, the oil Re–Os date suggests that oil generation in the Halahatang depression of the Tarim Basin occurred during the early Permian rather than the Silurian as previously proposed, with subsequent oil migration and accumulation occurring during the middle–late Permian as recorded by basin modeling, coupled with fluid inclusion analysis and illite K–Ar dating. In addition to promoting petroleum exploration in the Tarim Basin, this study, which combines crude oil Re–Os isotope dating and traditional analytical methods (organic geochemistry and fluid inclusion analysis) to constrain petroleum evolution, is applicable to hydrocarbon systems worldwide.

Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to the simulated fracture in Temco fracture conductivity system to mimic the practical treatment of temporarily plugging fracturing. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70o could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

Significant petroleum resources occur in the Ordovician carbonate reservoirs of the Tazhong area (Tarim Basin, China) in accumulations of black oil, volatile oil and condensate. However, the factors controlling the distribution of pools with different fluid phases remain poorly understood. Here, we integrate geological and conventional oil/gas geochemical data with an extensive dataset on diamondoids and propose a model for the occurrence of petroleum fluids in the area. Oils in the study area contain low variety and concentration of diamondoids and organic-sulfur compounds (OSCs) and have oil-dissolved wet gas mostly co-generated with oil. In contrast, liquids in the condensate reservoirs are significantly enriched in various types of diamondoids and OSCs, and have dry associated gas with methane enriched in 13C and relatively high content of H2S. We interpret that mature gas from deeper Cambrian strata, likely generated from thermally cracked oils and affected by thermochemical sulfate reduction (TSR), invaded the condensate reservoirs. Black oil reservoirs did not receive this late gas charge and this preserved their oil phase. The 1D burial history models and data on fluid inclusions suggest that oil charged all studied Ordovician reservoirs in the Late Permian – Triassic time, while the late gas charge occurred in selected reservoirs in the Late Himalayan time (∼10 Ma). Diamondoids proved to be useful indicators of the late gas charge as their variety and concentrations in liquids from the study area show good correlation with the extent of gas invasion.

Thiols (or mercaptans) in crude oils have been considered to be associated with thermochemical sulfate reduction (TSR). However, the molecular composition and the formation mechanism of thiols in c...

Diamondoids, resistant to thermal and biological destruction, are useful in identifying the genesis and alteration history of petroleum fluids, especially for condensates in which conventional biomarkers are of trace amounts. Tremendous condensate resources have been discovered in the Ordovician carbonates from the central Tarim Basin, however, the complex genesis and distribution of the condensates have brought challenges in effective exploration and fluid prediction. In this study, the GC × GC-TOFMS analyses were applied on several condensate oil samples. Results showed great variance in the distribution and absolute concentration of diamondoids. Accompany the integrated geochemical and geologic analyses, the studied condensates are ‘daughter’ condensates generated from the similar ‘parent’ condensates that have undergone severe phase fractionation induced by migration. Phase fractionation led to the constant loss of vapor fractions and enriched heavy fractions in the residual condensates during the migration of petroleum fluids towards structural highs. Accordingly, diamondoids were preferentially enriched in shallower condensates and depleted in residual condensates, such variations of diamondoids distributions are attributed to phase fractionation because diamondoids with different molecular sizes differ in the solubilities in vapor phase. This will bring insight into the genesis of secondary condensates and the evaluation of the fractionation extent of petroleum fluids, with which effective petroleum exploration and prediction can be obtained.

Giant petroleum accumulations worldwide with burial depths more than 7000 m (>23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (>6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.

A series of experiments, including natural gas molecular composition, carbon isotope analysis and fluid inclusion petrography and microthermometry were conducted to research the origin and formation of natural gases in the Middle Ordovician Yijianfang Formation and the Middle-Lower Ordovician Yingshan Formation, Gucheng-Shunnan block. Natural gases consist predominantly of methanes, with dry coefficients of 0.951–0.999 and have relatively heavy carbon isotopic signatures, with average δ13C1 and δ13C2 values of −36.4‰ and −32.5‰, respectively. The diagrams between δ13C-C1 versus C1/(C2 + C3) and methane carbon isotope versus ethane-propane isotopic separation suggest that these gases are oil-associated thermogenic gas from type Ⅱ kerogen with high thermal evolution extent of the source rocks. The empirical correlation of ln(C1/C2) and ln(C2/C3) indicates natural gases originated from crude oil cracking. Natural gases in the Gucheng block and the Shunnan block have properties similar to those of oil-cracking gases in the Eastern Lungu block and the Eastern Tazhong block. Due to reservoir temperatures being lower than formation temperatures of the gases and the potential of higher mature source rock being almost exhausted, natural gases originated predominantly from the cracking of deep paleo-oil pool rather than dispersive dissoluble organic matter in the source rocks. The comprehensive analysis of thermal evolution history, burial history, fluid inclusions and geological conditions suggest that natural gases formed during Himalayan stage. Deep oil-cracking gases accumulated in the Ordovician reservoir through migration along faults. Therefore, deep-seated natural gases have great potential for exploration.

The exploration activities in the eastern Tarim Basin have been thwarted over the last decade after the discovery of several Jurassic gas condensate fields. In this study, the two-dimensional gas chromatography/time-of-flight mass spectrometry (GC × GC-TOFMS) and compound-specific carbon isotope analysis were performed on a Jurassic condensate (Yingnan2) and the associated gas to determine its genesis and the accumulation process in this area. The geochemical and isotopic features suggested that the condensate analyzed was a mixture of the Ordovician cracked paleo-oil with the Jurassic intact oil as evidenced by the concentrated diamondoids and ethanoadamantanes, the high gas generation temperature (∼195 °C), the heavy whole oil δ13C (−28.6‰), and the significant variation in the isotopic profile of n-alkanes. As the gas amount was constantly elevated due to both oil cracking and the mixing of the kerogen-cracking gas from the Cambrian source rock, phase transition occurred and thus formed the Yingnan2 se...

The polar acidic compounds in the lately found Cambrian formation shale from Tarim Basin have been characterized by electrospray ionization Fourier transform ion cyclotron resonance mass spectromet...

Petroleum fluids in the deep Ordovician reservoirs of the Tarim Basin vary in phase and molecular composition. An improved understanding of the secondary geochemical alteration processes is critica...

Oil and gas in deep and ultra-deep strata has been a hot topic in both research and exploration. The understanding of reservoirs in relatively shallow strata may be of significance for deep exploration. The Hetianhe gas field is the only large gas field discovered yet in the southwest region of the Tarim Basin, with a small quantity of condensate oil penetrated and a burial depth ranging from 1035 m to 2885 m, and the origin and source of the oil and gas has long been unclear. By using comprehensive 2D gas chromatography/time of flight mass spectrometry (GC × GC-TOFMS), abundant diamondoids and some thiadiamondoids were detected in condensate oil samples collected from 3 wells, additionally, the features, including dry gas with a trace amount of hydrogen sulfide, heavy carbon isotopes, and similar sulfur isotopes in hydrogen sulfide and Cambrian gypsum, indicate that the oil and gas has undergone the thermochemical sulfate reduction (TSR) and thermal cracking. The current reservoir temperature, from 35 °C to 83 °C, does not meet the condition for the onset of these secondary geochemical alterations, therefore, the oil and gas may originate from deep strata. According to the reconstruction of the geologic evolution, deep oil and gas may have migrated vertically along faults and accumulated in the Hetianhe structure formed after 10 Ma to form the secondary gas reservoirs; hence it is inferred that favorable petroleum plays may exist in deep strata. The thick evaporite in the Middle Cambrian and the high-quality dolomite reservoirs in the Lower Cambrian constitute a favorable reservoir-seal assemblage, with the current depth between 8500 m and 10000 m and reservoir temperature above 200 °C, where the TSR and thermal cracking may occur. The sulfur isotope of hydrogen sulfide also demonstrates the occurrence of TSR process in the Cambrian strata. Therefore, large-scale of oil and gas reserves may be preserved in the stable zones in the Cambrian sub-salt strata, and it is suggested to strengthen hydrocarbon exploration in the Cambrian sub-salt strata in the southwest region of the Tarim Basin.

A giant deep-strata oil-gas field with complex fluid characteristics was recently discovered in the Hade-Yuke area of the east Tabei uplift (Tarim Basin, NW China). The deep fluids show a lateral co-existence of several gas, condensate and oil phase reservoirs characterized through the integration of complimentary geochemical (e.g., bulk composition, biomarker and stable carbon isotope) and geological data. Typical features of the gas and condensate reservoirs, which were mainly distributed in the eastern parts of the study site, included high GOR (gas-to-oil ratio), hydrocarbon gases with relatively heavy δ13C values and crude oils with high wax content. In contrast oil reservoirs, which mostly occurred in more westerly locations, had lower GOR values, lighter δ13C values and lower wax content, indicating gradual change of fluid characters. The petroleum accumulations derive from two hydrocarbon charge events: an early oil charge in the Late Hercynian and a later gas charge in the Late Himalayan which migrated from east to west, leading to a gradual variation in fluid phase and characteristics. Alteration of paleo oil reservoirs by this secondary gas charge was therefore primarily responsible for the complex fluid character and multi-phase reservoirs presently in place. Secondary condensates were formed from the retrograde condensation of paleo reservoirs. Our re-construction of the hydrocarbon accumulation process encourages future exploration endeavours to target commercially viable gas accumulations in the deep east strata and oil reservoirs in the west.

Paleocaves in carbonate reservoirs are the excellent oil and gas storage spaces in the field of petroleum exploration. Predicting the collapse depth of paleocaves in carbonate reservoirs has essential theoretical significance and applicable value for classifying of reservoir quality and delimiting lower depth of oil and gas exploration. Paleocaves in carbonate reservoirs are acted by overburden pressure, tectonic lateral compression, and fluid pressure in caves. In this study, paleocaves with irregular boundary shapes were abstracted as spheres with different diameters. Mechanical model of surrounding rocks of paleocaves was established to compute the stress states in 3–5 times diameter of caves. Through analyzing stress states in surrounding rocks, the destruction and collapse of caves was investigated. The diameters of caves in these models range from 0.01 mm to 10 m. Relationship between diameter of cave and collapse depth was obtained by fitting collapse depth of caves with different diameters. Above the collapse depth of caves with diameter 5 m is good reservoir zone. Between the collapse depth of caves with diameter 5 m and 2 m is effective reservoir zone. The interval of collapse depth of caves with diameter 2 m and 0.5 m is general reservoir zone. Below 11000 m, karst caves in carbonate reservoir nearly disappear. Numerical model of real paleocaves was established to simulate the deformation of single paleocave and paleocave group. The relationship between displacement of paleocave wall and depth of paleocave obeyed power law. The contiguous destruction and collapse occurred first between the paleocaves with small distance. The relationship can be used to classify the quality of carbonate reservoir and predict the lower depth of petroleum exploration.

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.