Search

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.

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.

A series of trace compounds (diamondoids, ethanodiamondoids, and thiadiamondoids) were detected through two-dimensional gas chromatography/time-of-flight mass spectrometry (GC × GC-TOFMS) analysis of Ordovician condensate samples from the Tazhong area. Gas chromatography-mass spectrometry (GC-MS) analysis showed that the biomarker parameters are less effective for high-maturity oils. Carbon isotope and geochemical features suggested that the gas is a high-temperature cracking gas when its temperature is higher than 170 °C. The H2S content is 8.27%, suggesting that it is affected by thermochemical sulfate reduction (TSR). However, the geological analysis indicated that the Ordovician reservoirs do not satisfy the conditions for TSR. The high-maturity oil in the Ordovician reservoirs may generate diamondoids and ethanodiamondoids when cracking, while TSR and severe cracking occur in deep Cambrian source rocks and produce a large number of diamondoids, ethanodiamondoids, organic sulfur compounds (OSCs), etc. The secondary geochemical products that are carried up by the dry gas and migrate upward through faults and are enriched in Ordovician crude oil reservoirs. On this basis, we proposed that the condensate presented was formed by the mixing of dry gas from Cambrian oil that was altered by cracking and TSR into Ordovician in situ slightly cracked oil, therefore speculating that the favorable reservoir–seal assemblages in this area may contain abundant oil and gas resources. Consequently, improved knowledge of secondary alteration effects on the reservoir and underground fluids is vital for oil and gas prediction and exploration development in the next step.

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.

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.

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.

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.

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 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

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...

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.

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.

Reservoired liquid petroleum has limited potential to be preserved under high temperature conditions due to thermal cracking and potentially thermochemical sulfate reduction, and thus exploration targets in ultradeep strata are mainly gas and condensate gas. However, a giant ultradeep liquid petroleum accumulation, with an average depth of >6500 m, was discovered recently in the Hadexun area, Tarim Basin. In this study, integrated geochemical analyses were conducted on the black oil samples from the Hadexun area. Intact terpanes and steranes and low concentration of diamondoids were detected, indicating that these oils were generated at peak oil window and were barely altered by secondary geochemical process (thermal cracking or others) despite their depth. The associated wet gas with light isotopic profiles was classified as mature oil-derived gas co-generated with the oil. Petroleum accumulation analyses suggested that the favorable carbonate reservoir bodies in the Middle Ordovician Yijianfang Formation were attributed to karstification and weathering, and mainly distributed along the major strike-slip fault belts. Together with the thick mudstones in the overlying Upper Ordovician Sangtamu Formation, they formed a favorable reservoir-seal assemblage in the Hadexun area. Massive volumes of liquid petroleum were generated and expelled from the Lower Cambrian black shales in the Late Hercynian and migrated into the Ordovician carbonate reservoirs through the strike-slip fault system, and subsequently were exposed to stable tectonic conditions. Due to the rapid subsidence since the Neogene, insufficient temperature-time exposure eliminated the impact of thermal cracking; therefore, the petroleum accumulation was preserved in the liquid phase, and further indicates that huge petroleum resource potential remains in ultradeep strata in the Tarim Basin.

Unraveling the accumulation and alteration process of reservoired petroleum is significant for the evaluation of petroleum potential. In this study, a paleo heavy oil from the TD2 well in the eastern Tarim Basin was investigated through integrated geochemical methods including two-dimensional gas chromatography coupled with time-of-flight mass spectrometry (GC × GC-TOFMS), gas chromatography-mass spectrometry (GC-MS) and compound specific carbon isotope analysis (CSCIA). Oil-source correlation analysis indicates that the TD2 oil accumulation is “self-generation and self-accumulation” within the Cambrian strata. Combined with tectonic evolution analysis, it is suggested that the oil experienced significant impacts due to changes in tectono-thermal process. Abnormally enriched polycyclic aromatic hydrocarbons (62.5 mg/g in total, 4- to 6- ring account for ~41 %) with few substituents suggest oil cracking due to a short-time high-temperature heating during rapid tectonic subsidence under higher geothermal gradient. Phase fractionation, as indicated by the physiochemical features and heavy isotopic values, was induced by severe tectonic uplift and denudation after accumulation, and resulted in the thickening, re-distribution, and destruction of the primary oil pool. After that, the TD2 oil pool was preserved from further alterations under steady tectonic setting with a low geothermal gradient. Four accumulation assemblages in the eastern Tarim Basin were identified and compared, indicating that great oil and gas potential remains including oil/heavy oil in the Cambrian assemblage and light oil/condensate in the Jurassic and Silurian assemblages. Future exploration should focus on locally developed favorable reservoirs with good preservation conditions.

The global Precambrian–Cambrian system includes an important series of hydrocarbon-bearing strata. However, because rocks of this age are typically deeply buried, few petroleum exploration breakthroughs have been made, and the presence of source rocks remains somewhat controversial. Recently, commercial condensate and gas were discovered from the deep (∼6900 m [∼22,600 ft]) Zhongshen 1C (ZS1C) exploratory well drilled in the Tazhong uplift of the Tarim Basin, China, leading to renewed interest in the development of Cambrian source rocks in the basin. On the basis of outcrop reconnaissance and sample testing from around the Tarim Basin, we show that a set of high-quality source rocks were developed within the lower Cambrian Yuertusi Formation (J1y), at the base of the lower Cambrian. These rocks are black shales and typically have a total organic carbon content between 2% and 6% but extending as high as 17% in selected regions. This marine sequence is 10–15 m (33–49 ft) thick in some outcrops along the margins of the basin. Seismic data indicate that these high-quality source rocks may cover an area as large as 260,000 km2 (100,000 mi2). Their main organic parent material was benthic multicellular algae. On the basis of high-temperature thermal simulations conducted on these source rocks, we show that the gas composition and carbon isotopes from the ZS1C well are similar to the products generated at a thermal evolution stage corresponding to a vitrinite reflectance of between 2.2% and 2.5%. Late-stage natural gas accumulated within these rocks over time. The δ34S correlation of organic sulfur compounds in the condensate with Cambrian sulfates provides further evidence for a J1y source rock origin of the ZS1C condensate and gas. The Cambrian dolomites in association with a salt seal exhibit favorable geological conditions for large-scale hydrocarbon accumulation. A new set of deep exploration strata can, therefore, be developed, guiding future deep Cambrian hydrocarbon exploration in the Tarim Basin.

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

Thermal stability of liquid petroleum in the subsurface is closely linked to reservoir temperature. Most oil accumulations occur at temperatures 150–160 °C leading to the dominance of gas condensate and free gas accumulations in ultra-deep high-temperature reservoirs. The recently drilled Fuyuan-1 exploration well (northern Tarim basin) produced high-quality non-cracked single-phase (black) oil from a carbonate reservoir located at maximum depth 7711 m and temperature 172 °C. This is the deepest oil discovery in China to date and among the deepest in the world. The oil density (0.825 g/cm3 at 20 °C or API gravity 40°), relatively low gas/oil ratio (135 m3/m3 or 758 scf/bbl), low variety and abundance of adamantanes as well as lack of thiaadamantanes and dibenzothiophenes indicate that the oil was expelled from a source rock at moderate thermal maturity and has not been cracked. The molecular and isotopic composition of oil-associated gases are consistent with this interpretation. We suggest that the oil remained uncracked because the residence time at temperatures >150-160°C was relatively short (

Diamondoids are often enriched in highly mature oil due to their high resistance to thermal stress. Ethanodiamondoids have similarly high thermal stability. We have detected ethanodiamondoids from 75 oil samples from deep marine carbonate strata in the Tarim Basin, China. Based on thermal simulation experiments on source rock and oil samples, we propose that ethanodiamondoids are gradually created with increasing thermal evolution and oil cracking. Their formation is likely due to free radical reactions of diamondoids with ethane or ethene formed from the cracking of alkanes. A proxy is proposed for the rapid determination of the degree of oil cracking and the petroleum phase based on the relationship between types and concentrations of ethanodiamondoids and diamondoids.

The Proterozoic is demonstrated to be an important period for global petroleum systems. Few exploration breakthroughs, however, have been obtained on the system in the Tarim Basin, NW China. Outcrop, drilling, and seismic data are integrated in this paper to focus on the Neoproterozoic rift basins and related hydrocarbon source rocks in the Tarim Basin. The basin consists of Cryogenian to Ediacaran rifts showing a distribution of N-S differentiation. Compared to the Cryogenian basins, those of the Ediacaran are characterized by deposits in small thickness and wide distribution. Thus, the rifts have a typical dual structure, namely the Cryogenian rifting and Ediacaran depression phases that reveal distinct structural and sedimentary characteristics. The Cryogenian rifting basins are dominated by a series of grabens or half grabens, which have a wedge-shaped rapid filling structure. The basins evolved into Ediacaran depression when the rifting and magmatic activities diminished, and extensive overlapping sedimentation occurred. The distributions of the source rocks are controlled by the Neoproterozoic rifts as follows. The present outcrops lie mostly at the margins of the Cryogenian rifting basins where the rapid deposition dominates and the argillaceous rocks have low total organic carbon (TOC) contents; however, the source rocks with high TOC contents should develop in the center of the basins. The Ediacaran source rocks formed in deep water environment of the stable depressions evolving from the previous rifting basins, and are thus more widespread in the Tarim Basin. The confirmation of the Cryogenian to Ediacaran source rocks would open up a new field for the deep hydrocarbon exploration in the Tarim Basin.

The West Kunlun Orogenic Belt (WKOB) is a key area for evaluating the evolution of the Proto-Tethys Ocean. To constrain this history, we present geochemical and zircon U-Pb geochronological data from a suite of metasedimentary rocks within this orogenic belt. Detrital zircons ages are clustered between 1000 and 400 Ma, with major peaks at ca. 510 Ma and 460 Ma, and minor peaks at ca. 840 Ma and 650 Ma. The age groups younger than 1000 Ma broadly overlap magmatic activity at ca. 540–420 Ma and minor magmatism at 920–540 Ma in the WKOB. The age data also reveal Early Paleozoic metamorphic basement rocks in the WKOB that were probably sourced from Kunlun terranes and blocks of Gondwanan affinity rather than the Tarim Craton. Compiled geochemical data suggest a protracted subduction setting in the WKOB in the Early Paleozoic. eHf(t) values show increasing trends at 900–740 Ma and 740–600 Ma and a distinct decreasing trend at 540–420 Ma, consistent with retreating subduction during the Neoproterozoic and advancing subduction in the Early Paleozoic. The retreating-advancing subduction cycle in the WKOB was possibly related to the opening and closure of the Proto-Tethys Ocean along the margin of Gondwana.

The widespread lower Cambrian black shales reflect a significant anoxic event during a global transgression, recording synergistic changes in the marine environment and biological evolution. Extremely high Hg (714–6187 ppb, average is 3380 ppb) contents and Hg to total organic carbon ratios (Hg/TOC: 120–765 ppb/wt.%) were observed in the Danquan section of South China, suggesting that extensive volcanic activities may occur during the early Cambrian. The redox condition of the Danquan section is euxinic as evidenced by multiple redox proxies, which include U/Th, V/Cr, Corg/P and authigenic enrichment of redox sensitive elements (MoEF, UEF). The Co*Mn – Al crossplot revealed that black shale developed in different geographical settings (upwelling setting for the Interval I, and restricted condition for the Interval II). Besides, the sedimentary Hg is hosted in different phases in the two intervals: in organic matter for the Interval I, and in sulfides for the Interval II. Moreover, the anomalous enrichment of Hg in both intervals document the Hg controlled by geographical settings and host phases. Thus, volcanic activities and geographical settings both constrain the evolution of life, as well as redox conditions.

The Tarim Craton is the largest petroliferous basin in China, and thick chert have been found in the Ordovician carbonate reservoir during drilling. Owing to the tight chert, the storage performance may decrease and lead to drilling failure. In this study, silicon, oxygen, and strontium isotope compositions of chert were tested to constrain the source and migration of Si-rich fluids, which is helpful for understanding the reservoir and avoiding drilling failure. The Ordovician silicon dioxide in cherts have δ30Si values from +1.29‰ to +3.50‰, δ18O values from 20.21‰ to 27.50‰, and 87Sr/86Sr values from 0.709 to 0.714. The correlation between δ30Si- and δ18O reveals that the formation of cherts is related to the activity of low-temperature hydrothermal fluids, and the value of 87Sr/86Sr indicates the contribution of the deep crust source to the silicon-rich fluid. Comprehensive analyses showed that the deep thermal fluid was active during the formation of cherts. The late Hercynian tectonic movement led to the development and activity of deep and large faults, and the deep-source silica hydrothermal fluid entered the Ordovician reservoir along the fault from bottom to top, filling the pores, densifying the rocks, and causing deterioration of the storage performance. Therefore, through multi-geochemistry (Si-O-Sr isotopes), the spatial distribution characteristics of silica can be determined to avoid the distribution interval and member of silica during drilling. Moreover, the identification and distribution prediction of the genesis of cherts is of great significance for oil and gas exploration.

Early Cambrian shale-chert couplets are widely distributed in South China, within which abundant organisms have been detected. Cherts in early Cambrian are known to be influenced by hydrothermal activity. However, the influence of syngenetic hydrothermal activity on organism preservation has not yet been well evaluated. Litho-, chemo- and bio-stratigraphic data have documented that the syngenetic hydrothermal silica fluid activity from the Majiang-Yangtiao section of the early Cambrian Niutitang Formation in Guizhou province, SW China. Geochemical compositions [Fe/Ti, Al/(Al + Fe), Al–Fe–Mn ternary diagram and Fe/Ti vs. Al/(Al + Fe + Mn) diagram] indicated that the chert, siliceous shales and mudstones were strongly, moderately, and weakly influenced by hydrothermal silica fluids, respectively. Mudstones contained much more terrigenous elements (e.g. Al and Zr). The total organic carbon (TOC) content and concentrations of nutrient elements (Cu, Zn, P, Ba) were highest in siliceous shales, followed by mudstone and lowest in chert. This could be due to a high silica dilution from hydrothermal fluid in chert. Compared with the contiguous siliceous shales, chert was characterized by a high content of aerobic zooplankton (e.g. sponges and pogonophoras) with low V/Cr ratios. This represented a sedimentary facies altered by hydrothermal fluid input in the marine environment. Organisms were well preserved in chert with delicate ornamentation on the surfaces of spherical acritarch cells, and to a lesser extent in silica-rich siliceous shales, but less in mudstones. This suggested that hydrothermal silica fluid with rapid sedimentation provided a good environment for organism preservation. These well preserved organisms could provide organic carbon content with little or no hydrocarbon generation in the rocks, because the morphology were not changed and no solid bitumen were found surrounding these organisms. The study provided a clue for careful consideration in the context of hydrocarbon generation evaluation in early Cambrian source rock.

The Ordovician of the Tazhong area in the Tarim Basin has suffered multi-cyclic hydrocarbon charging, making Tazhong a typical condensate gas district. In this paper, production and test data were gathered and a detailed comparison was conducted on the geology and the fluid distribution and characteristics between the eastern and western Tazhong area. Eastern and western regions exhibit significant differences in tectonic structure, fluid distribution, and physical-chemical properties of oil and gas. Compared with the eastern region, the western part has a greater development of discordogenic gas associated with strike-slip faults which, combined with the Tazhong No. 1 fault zone, control the fluid distribution. The eastern region is mainly controlled by the Tazhong No. 1 fault zone. Fluid have markedly homogeneous properties in the east, but are heterogeneous in the west. The origins of oil and gas are different between the east and the west. In the east, hydrocarbons are mainly from Ordovician source rocks and natural gas is mostly derived from kerogen pyrolysis. In the west, the hydrocarbons mainly originated from Cambrian source rocks, and the gas was mostly generated by crude oil cracking. In sum, the east region is dominated by primary condensate gas reservoirs, and the western region is dominated by secondary condensate gas reservoirs. Because of the different geological settings and fluid physical properties, differences in the condensate gas reservoirs in the eastern and the western Tazhong area have been analyzed, and appropriate formation mechanisms for condensate gas origins are established.

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.

Heavy oil accumulation in deep Ordovician carbonate stratum was discovered at present burial depths greater than 6600 m in the northern Tarim Basin, NW China. Density of the unusual ultra-deep heavy oils is greater than 0.92 g/cm3 at 20 °C. Crude oil produced from 6598 to 6710 m interval of the Ha9 well was selected for the thiophenic and sulfidic compounds characterization in order to understand the mechanism of heavy oil accumulation in the ultra-deep strata. In addition to the common thiophenic compounds, four homologues of novel polycyclic sulfides named as 1,1,4a,6-tetramethyl-9-alkyl-1,2,3,4,4a,9b-hexahydrodibenzothiophenes (H6DBTs, 9-alkyl = H, methyl, ethyl, and propyl, respectively) were identified in Ha9 well crude oil, and it is the first time these biomarkers were detected in natural occurrence. H6DBTs were generated from isoprenoid-related precursors reacted with reduced-state sulfur in early diagenesis stage by bacterial sulfate reduction. The occurrence of H6DBTs further indicated biodegradation of the reservoir oil at a relatively mild temperature (60–65 °C), a favorable condition for microorganism survival. According to the history of reservoir forming, oil and gas accumulation occurred in reservoirs during the Late Permian period and then being uplifted, suffering biodegradation. Oil quality was significantly altered as a result of strong biodegradation since the Triassic. Heavy oil reservoir was buried deeper around. 5 Ma, leading to a rapid increase in reservoir temperature up to 150 °C at a burial depth of 6600 m. The quick burial and elevated temperature of the reservoir were favorable to the preservation of H6DBTs.

The Cambrian is an important period for life evolution during the geological history, and the basal Cambrian black shales with widespread occurrence worldwide record important paleoceanographic information during this critical period. The set of shales with stable distribution and thickness of about 200 m is also extensively developed in South China, which provides an important material for studying the marine redox environment, major geological events and biotic evolution. Here we conduct studies on the nitrogen cycle and mercury's abnormal enrichment based on mercury (Hg) concentrations and nitrogen (N) isotope compositions of the shales from the lower Cambrian Niutitang Formation in Tongren area of Guizhou Province, South China. The results show that both Hg and TOC exhibited abnormal enrichments at the bottom of the Niutitang Formation. Mo and U enrichment factors indicated a gradually oxidized redox evolution during the deposition of the Niutitang Formation, with two fluctuated redox cycles from reducing to oxic, and then from dysoxic to oxic conditions in the water column. And the abnormal enrichment of Hg during the early Cambrian may be related to the volcanic and hydrothermal activities. Nitrogen isotope (δ15N) has obvious negative shift at the bottom of the Niutitang Formation, which indicated that nitrogen fixation was enhanced under the anoxic condition in the water column, the organic carbon pool gradually reduced, and phosphorus (P) and other nutrient elements were available, leading to the enhancement of nitrogen fixation and an increase of bioavailable nitrogen in the water column. Nitrogen isotopes recorded the effects of early Cambrian biological evolution and marine redox environment on nutrient element circulation, with contemporaneous volcanic or hydrothermal fluid activities during this period.

The petroleum exploration well Luntan-1 (LT1) located in the Tabei Uplift, Tarim Basin, China reached vertical depth 8882 m and is now the deepest well in Asia. A significant petroleum flow (134 m3 of oil and 45,900 m3 of gas) was obtained from the Cambrian Wusongger Formation perforated in the interval 8203–8260 m, with a pressure of 90.8 Mpa and interval logging temperature is 162 °C. The well LT-1 is the deepest producer of oil from Paleozoic reservoirs in the world. According to the analysis of the effect of acidizing fracturing reservoir reconstruction, the Lower Cambrian Wusongger Formation has low pump stop pressure, large pressure drop, fast deceleration, and good reservoirs and the lithology are limestone dolomite, lime-bearing dolomite, and dolomite. The source rock is the Lower Cambrian Yuertusi shale containing significant amount of total organic carbon (2–30 wt%) and located in the late oil/early gas maturity window (vitrinite reflectance 1.4–1.7%). Through GC × GC-TOFMS analysis of this oil showed low concentration of diamondoids, which indicates lack of thermal cracking of oil to gas. Thiadiamondoids, typically indicative of thermochemical sulfate reduction, were not detected. Using kinetic calculations, we estimated the temperature threshold for thermal cracking of well LT1 oil to gas at ~210–220 °C. Based on the thermal evolution and burial history of the Tarim Basin, the depth threshold for the disappearance of liquid oil is ~9000 m. Low geothermal gradient (19.6 °C/km) and rapid subsidence after petroleum accumulation jointly contribute to the preservation of liquid petroleum in ultra-deep strata in the Tarim Basin. Our findings suggest that the favorable exploration area in ultra-deep, high-temperature and high-pressure Cambrian reservoirs in the Tarim Basin exceeds 20,000 km2 and may contain over 1 billion tons of oil resources. Furthermore, the significant discovery of oil in the well LT1 provides important insights for global exploration of Paleozoic ultra-deep oil.

The early Cambrian was an important interval in Earth history, marked by significant evolution of both life and the marine environments it inhabited. While enhanced hydrothermal activity has been proposed as a trigger for ecosystem perturbations in the early Cambrian, it remains unclear how intense and how long such perturbations may have been. To address this, we examined mercury (Hg) concentrations and mercury isotopes, as well as major and trace elements, of organic-rich black shales of the lower Cambrian Niutitang Formation, in the Tongren area of Guizhou Province, South China. Our data show that Hg in these sediments is hosted dominantly by organic matter. Elevated raw and normalized Hg contents provide direct evidence of intense hydrothermal activity during the early Cambrian in South China. We suggest that high metal flux (e.g., Mo, U, and Ba) into the seawater occurred through this intense submarine volcanism, altering seawater compositions. Intense hydrothermal activity was likely a significant trigger of environmental and biological evolution during the early Cambrian in South China.

The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000–8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.

The accumulation assemblages in the deep Jurassic and Cretaceous strata of the southern margin of the Junggar Basin (SMJB) have favorable petroleum accumulation conditions. Due to the huge burial depth, gas/condensate gas reservoirs are expected as the main targets, however, barely any exploration breakthrough has been achieved. The recently drilled well GT1 has obtained a high oil production of >1200 tons/day in the deep Cretaceous strata, which was classified as low gas-to-oil ratio (GOR) light oil. This is the first significant breakthrough in the deep assemblages in the SMJB which brings to the question of its genesis and preservation and the true petroleum potential in the area. In this study, we have presented integrated geochemical analyses including GC × GC-TOFMS, GC-MS and stable carbon isotopes and thus to conclude that the GT1 oil was sourced from Jurassic coal-measure source rocks with maturity of 0.7–0.9%Ro. As only a small amount of diamondoids and ethanodiamondoids were detected, the GT1 oil was classified as normal mature oil well preserved from thermal cracking despite its huge burial depth. The associated gas is coal-type gas with relatively high wetness and the similar maturity to that of the oil. According to the hydrocarbon accumulation analyses, the main source rocks were developed in the Lower-Middle Jurassic with present-day maturity of 1.0%–2.0%Ro. The sandstones developed in the transitional facies in the overlying Lower Cretaceous Qingshuihe Formation were impacted by the tectonic compression and preserved as belt-like distribution in anticline traps. Regional Cretaceous Tugulu Group also overlie these sandstone facies. This forms a favorable source-reservoir-seal assemblage for oil and gas accumulations in the area. Therefore, the deep assemblage in the SMJB is favorable for the accumulation and preservation of large-scale oil reservoirs and shows great potential for liquid petroleum exploration.

The origin of magmatic episodes between final assembly and initial breakup of Rodinia is crucial for deciphering geodynamic transition and continental crust growth processes. However, few igneous rocks were identified during the quiescent time from 900 Ma to 830 Ma in the Tarim Craton. Along its northwestern margin, our field investigations identified abundant granitic debris in the Cryogenian Qiaoenbrak Group. Zircon U-Pb age determination revealed crystallization age at ca. 850 Ma. Detrital zircon crystals within Cryogenian to Ediacaran clastic rocks and schists of the basement Aksu Group also contain a major population having crystallized at ca. 860–840 Ma. Thus, we suggest that a hitherto unknown major magmatic event occurred ca. 850 Ma ago in northern Tarim. Granite gravels exhibit typical fractionated granite features, with high values of SiO2 (73.1–75.7 wt%), alkali oxides (Na2O + K2O = 7.8–8.7 wt%) and Na2O/K2O (avg. 1.3 wt%), and low values of P2O5 (≤0.04 wt%) and A/CNK (0.87–1.01), together with Rb, Th, U and K enrichment, and depletion in Nb, Ta, Sr, P, Ti and Eu, negative Eu anomalies (δEu = 0.21–0.74) and fairly low Ga/Al ratios. Including detrital crystals, ca. 850 Ma zircon crystals display a large range of eHf(t) values from −17.0 up to +11.6. Elemental and zircon Hf isotopes suggest that granites were derived from melting of juvenile lower crust, with addition of reworked upper crust and mantle-derived melts. We propose (1) before ca. 850 Ma, arc-continental collision setting related to southward accretionary assembly along Tarim margin, (2) progressive assembly of Tarim Craton, and (3) position of Tarim Craton within Rodinia supercontinent probably closer to North India Block than to Australia at ca. 850 Ma.

A continental condensate field, with the deepest burial depth (7084 m) so far in China, was recently discovered from the Cretaceous sandstone reservoir in the Bozi area of the Kuqa Depression, Tarim Basin. In this paper, we report general features of this field, including geochemistry of the condensates, their origin, and migration and accumulation. General geochemistry of the condensate reflects that it is an over pressured condensate reservoir. Analytical results by newly-developed high-resolution GC × GC–TOFMS method indicate that the condensate is rich in n -alkanes from nC 3 to nC 34 and in diamondoid hydrocarbons with a high content of adamantanes. The condensate has a high abundance of aromatic hydrocarbons. The gas δ 13 C 2 values in these are −23.3‰, which is characteristic of coal-derived gases. Compared with the contents of conventional condensate oils, the BZ1 well has a high content of aromatic hydrocarbons, suggesting that the condensate is in a stage of highly mature cracking. Analyses of oil biomarkers, carbon isotopes, gas compositions, etc., revealed that the condensate is dominantly sourced from the highly mature coals of the Jurassic Qiakemake Formation in the western Kuqa Depression. This set of coal source sequences has generated large quantities of condensate since 3 Ma, when the study area was subjected to a rapid subsidence with sediments over 2000 m and consequently attained at the condensate-generating stage. Such condensates then migrated vertically into the Cretaceous traps along faults. Therefore, the Bozi condensate field is a typical case of large-scale oil/gas field characterized by late-stage accumulation. Multiple elements favor the formation of this large-scale condensate field. The timing of trap formation accords with that of the condensate generation (since 3 Ma). The traps and source rocks are stacked vertically. Faults connect the source rock sequences and the reservoirs. The hydrocarbon charge is strong and efficient. Thick Paleogene gypsum beds act as an excellent cap rock, favoring the accumulation and preservation of the condensate.

An estimated trillions of cubic meters of natural gas have recently been discovered in the Sinian dolomite reservoirs in the Sichuan Basin, China. The 20–26 m thick reservoirs were found in deep structural–lithologic traps of 5000–5500 m deep. The Sinian gas is thought to have been derived mainly from the Sinian source rocks, and partly from the Cambrian source rocks. The gas is thermally matured, with a dryness ratio (C1/∑C1–4) of 0.997–0.9998, C2H6 content

Over the past five years, oil and gas exploration to marine facies carbonate rock in China took on a fast-growing tendency, and a lot of large-scale oil and gas fields were discovered in succession. Particularly in the north of Tarim Basin, the large-scale Rewapu oil field was recently discovered in the Ordovician carbonate rock layer system with buried depth of 7,000 meters, manifesting that a significant potential of exploration exists in Tarim Basin's deep layer and ultra deep layer of Tarim basin. The results indicate that reservoirs of Rewapu oilfield are low porosity and low permeability layers karst reservoirs, reservoir temperature is around at 160 °C with oil, and the crude oil comes from the upper Ordovician source rock of the Manjaer depression. The hydrocarbon accumulation time is in the Late Permian, and since the Triassic sedimentation, the reservoir is in the continuous process of burying. It belongs to the old oil and gas system. Due to low geothermal gradient and late quick deep burial, oil reservoir has yet to be cracked, so well-preserved old oil reservoir can be discovered at the depth of 7000 m. The Ordovician carbonate reservoir in Rewapu was a fracture-cavity oil reservoir, and the oil and gas distribution and enrichment are controlled not by the local structure, but by the distribution and the development degree of Ordovician carbonate reservoir. The reservoirs of Rewapu block are mainly distributed in the Ordovician Yijianfang formation and at the top Yingshan formation, and the reservoir development degree was controlled by the karstification, the degree of fracture development and the sedimentation facies, concentrating into belts in plane and not controlling by the depth vertically. The overlying strata are limestone of Tumuxiuke formation and marls and limestone of Sangtamu formation in the upper Ordovician. Rewapu oil reservoir features stratified oil and mainly contains normal oil with low viscosity and high wax. Research results show that Ordovician reservoirs in Rewapu block have relatively large depth of burial, but they are still favorable in quality and sit along the path for the oil and gas's northward migration. Therefore, this block has immense resources potential and boasts good exploration and development outlook. In this paper, we study Rewapu block oil reservoir's geological features and hydrocarbon accumulation mechanism, which is of important significance for directing the exploration to oil and gas at the deep layer and ultra deep layer of Tarim Basin.

In this paper, we analyse the Ordovician condensate in the Tazhong area of the Tarim Basin, NW China, using a new high-resolution comprehensive two-dimensional gas chromatography with time-of-flight mass spectrometry (GC × GC-TOFMS). Results show that 4778 compounds at a signal-to-noise ratio of more than 100 were detected, reflecting the advantage of this method in the analysis of condensate. Abundant adamantane series compounds and some diamantane series compounds, as well as a series of sulphur-containing compounds (including the benzothiophene series, and the dibenzothiophene series) were detected for the first time in the study area. Combined with the results of a study on oil and gas sources and migration/accumulation, we address the origin of these compounds. It is implied that the diamondoids were not formed in-situ due to oil cracking (in reservoir approximately 5500 m deep at temperature around 139 °C), whereas the cracking of oil to gas may have occurred in the deeper-buried Cambrian dolomite reservoir at a reservoir temperature of 180–220 °C (8500–11,000 m depth). The oil-cracked gas (secondary cracking product) might have migrated to and accumulated in the shallower-buried Ordovician reservoir, accompanied by abundant diamondoids. The formation of sulphur-containing compounds may be related to thermochemical sulphate reduction (TSR), which, similar to the oil cracking, took place in the deeper-buried Cambrian reservoir. Under high-temperature TSR, SO 4 2− in the formation water is reduced to H 2 S and organic sulphur compounds, leading to the enrichment of sulphur in crude oils (e.g., benzothiophene, and dibenzothiophene series). As such, it is implied that the Tazhong area could potentially be explored for deep-buried oil-cracked gas.

Gas condensate and natural gas samples from wells ZS1 and ZS1C in the Cambrian strata of the Tarim Basin, NW China are analyzed geochemically to assess thermal maturity, extent of oil cracking and secondary alteration. Hydrocarbons are derived from the Cambrian source rocks with gas condensate and solution gas reservoired in the Middle Cambrian Awatage Formation and dry gas in the Lower Cambrian Wusonggeer and Xiaoerbulake Formations, where caverns from dolomitization and local fractures provide spaces for petroleum accumulation. Gas and gas condensate in the Middle Cambrian are mainly generated from kerogen thermal degradation at high maturity stage (condensate–wet gas window) rather than from in-reservoir thermal cracking of preexisted oils. Evaporative fractionation exerts certain impacts on gas condensates as evidenced by enrichment of light molecular weight alkanes, depletion of diamantanes in one condensate, and low aromaticity. Condensate in well ZS1C is a thermochemical sulfate reduction (TSR) alt...

Ordovician carbonates have abundant resources of oil and gas in the Tazhong area of the Tarim Basin. Due to secondary alteration caused by multiple periods of oil and gas filling, especially late gas filling, fluids in ancient oil reservoirs are complex in nature, and multiple-phase oil and gas reservoirs, such as gas-condensate reservoirs, volatile-oil reservoirs, and normal oil reservoirs coexist horizontally. By examining the distribution, fluid physiochemical properties, biomarkers, gas isotopes, and fluid inclusions of these oil and gas reservoirs, this research has revealed that reservoir distribution is controlled by strike-slip faults, fracture-vuggy reservoir connections, and structural features, and that fluids of different-phase reservoirs are significantly different in physiochemical properties and in nature. Maturities of oil and gas are significantly different, suggesting that the area was filled at least twice by oil and gas of different maturities. Analysis of fluid inclusions shows that two types of inclusions are commonly developed: liquid–hydrocarbon inclusions in the first period and gaseous hydrocarbon inclusions in the second period, suggesting that oil filled at an earlier time and gas filled at a later time. It is proposed that gas-condensate reservoirs were formed after late gas invasion altered ancient oil reservoirs. Features of light hydrocarbons, such as wax and aromaticity, indicate the direction and intensity of gas-washing fractionation; biomarker parameters prove that, in terms of oil and gas maturity, gas-condensate reservoirs>volatile-oil reservoirs>normal oil reservoirs. The process of oil and gas accumulation in the Tazhong area is reproduced, and an accumulation model is proposed for multiple-phase oil and gas. In addition, a method is provided for evaluating the relative intensities of secondary alteration to early reservoirs by late gas filling, which is significant in exploration for oil and gas in deep layers and in prediction of hydrocarbon phases.

Tazhong is located in the interior of the Taklamakan desert in the Tarim Basin. Deep carbonates are targeted exploration areas with abundant gas, and the largest Ordovician gas-condensate field has been discovered. The hydrocarbon is mainly distributed in the reef-shoal complex of the upper Ordovician Lianglitage Formation and in the interbedded weathered reservoirs of the lower-middle Ordovician Yingshan Formation. Despite the deep burial depth of the reservoirs and strong heterogeneity, the reservoir bodies are large, multiple-layered, and enrichment in hydrocarbons indicates a great exploration potential. The Ordovician gas-condensate reservoir in the Tazhong consists mainly of methane with a gas dryness coefficient of 0.91–0.98. The Ordovician gas in the Tazhong belongs to secondary (oil cracking) gas. The comprehensive analysis of natural gas composition, stable carbon isotopes and adamantane content showed that the natural gas was from paleo-reservoir cracking at depth. Basin geothermal history, burial history, fluid inclusion data and geological analysis show that the gas accumulation occurred 5 Ma ago. The sulfur isotope of sulfides, the presence of 2-thia-adamantane and existence of light CO 2 carbon isotopes indicate that the H 2 S was formed via TSR. The natural gas accumulated through migration along faults.

The Western Slope of the Songliao Basin is rich in heavy oil resources (>70 × 108 bbl), around which there are shallow gas reservoirs (∼1.0 × 1012 m3). The gas is dominated by methane with a dryness over 0.99, and the non-hydrocarbon component being overwelmingly nitrogen. Carbon isotope composition of methane and its homologs is depleted in 13C, with δ13C1 values being in the range of −55‰ to −75‰, δ13C2 being in the range of −40‰ to −53‰ and δ13C3 being in the range of −30‰ to −42‰, respectively. These values differ significantly from those solution gases source in the Daqing oilfield. This study concludes that heavy oils along the Western Slope were derived from mature source rocks in the Qijia-Gulong Depression, that were biodegraded. The low reservoir temperature (30–50 °C) and low salinity of formation water with neutral to alkaline pH (NaHCO3) appeared ideal for microbial activity and thus biodegradation. Natural gas along the Western Slope appears mainly to have originated from biodegradation and the formation of heavy oil. This origin is suggested by the heavy δ13C of CO2 (−18.78‰ to 0.95‰) which suggests that the methane was produced via fermentation as the terminal decomposition stage of the oil.

Fifty-three oil samples from Paleozoic marine reservoirs of the Tarim Basin were analyzed by GC–FID and GC–MS to elucidate the influence of biodegradation and mixing on molecular compositions. Biodegradation has a major impact on many classes of compounds but the ultimate compositions and physical properties of the oil are influenced strongly by mixing with late oil charge, subsequent to the process of biodegradation. Almost all samples display biodegradation signatures, characterized by variable size of the unresolved complex mixture (UCM) and variable amounts of 25-norhopanes (25-NHs) and 17-nortricyclic terpanes (17-NTs). The ubiquitous occurrence of n -alkanes suggests that the petroleum accumulated in these fields is mainly a mixture of previously biodegraded oils with later migrated fresh oils. The unaltered late charge of oil, which has commingled with the initial biodegraded charge, gives the wide range of oil gravities and asphaltene contents observed. Most commonly used maturity and depositional environment diagnostic parameters in the saturated hydrocarbon fraction are affected by biodegradation. Based on the intensity of 25-NHs and 17-NTs, oils from the Tabei Uplift appear to have experienced a much greater degree of biodegradation than those from the Tazhong Uplift. However, we caution against the simplistic use of molecular indicators to define a specific level of biodegradation in this case study, as it may be somewhat misleading for physical property prediction. A wide range of estimated maturity values from different components provides an important clue for multiple charge and mixing interpretations. The relationship between the absolute concentrations of compound class and peak/hump ratios of the samples can potentially, qualitatively differentiate the pulse of inputs to the mixed oils. The positive correlation between the concentrations of a given compound class and peak/hump ratios may suggest that that class of compounds is most likely derived from the late charge after biodegradation, while the negative correlation may indicate compounds largely inherited from the early charge before biodegradation. Some compounds show almost no correlation between their concentrations and peak/hump ratios, implying more similar intensity of charge inherited from early pulse and amalgamated from later pulses. In some extremely biodegraded cases where UCM hump can also be diminished (not in present case study), the correlation between compound class concentrations and peak/hump ratios will be more complicated.