Permian Source Rocks Research Articles

Modelling a foreland fold-and-thrust petroleum system: a Permian example in the NW Sichuan Basin, Southwest China

ABSTRACT Foreland thrust belts are globally significant areas for oil and gas exploration. These belts undergo unique tectonic activity, resulting in distinct variations in the accumulation of oil and gas. Studying the genetic evolution of deep oil and gas in these thrust belts is a crucial means of revealing the patterns of deep oil and gas accumulation. This study utilized a novel approach that combines reservoir geochemistry and basin simulation to determine the migration process of oil and gas in the foreland thrust fault belt of northwestern Sichuan Province. To achieve this goal, we established a thermal evolution model of lower Palaeozoic source rocks through organic chemical analysis. The balanced profile technique was used to determine the paleotectonic evolution pattern of the critical period in this area. Additionally, the mixed flow migration algorithm was employed to simulate the evolution of the Palaeozoic petroleum system. Through basin petroleum system modelling (BPSM), it was discovered that the bitumen found in the thrust nappe belt originated from the lower Cambrian strata. Furthermore, the gas reservoir in the hidden fault belt primarily migrated from the lower Cambrian strata and was also partially mixed with thermogenic gas from Permian source rocks. After establishing the genetic models of various tectonic belts in the study area, it became clear that there are notable differences in hydrocarbon accumulation within these belts. The BPSM results revealed that the oil present in the thrust nappe belt was generated in Lower Cambrian source rocks through early Indosinian hydrocarbon expulsion and continuous charging. The gas found in the thrust nappe belt was produced through the process of oil cracking in the deep reservoir located in the hidden front belt during the late Indosinian. The depth of the thrust nappe belt has helped to preserve hydrocarbon reservoirs. The natural gas present in the hidden fault belt primarily originates from lower Cambrian source rocks, which are combined with gas generated by oil cracking in lower Permian source rocks after the Yanshanian. Therefore, hydrocarbons accumulate deeply in the footwall of the thrust fault belt. The BPSM offers a fresh approach to hydrocarbon genetic models of thrust fault zones in the western Sichuan Basin, and it is beneficial for accurately evaluating the potential for deep hydrocarbon resources in comparable geological settings.

Three-stage hydrocarbon accumulations in the Middle Permian in the Central Sichuan Basin

The Middle Permain Maokou Formation (P2m) is a new region of natural gas exploration in the Sichuan Basin, is characterized by bioclastic limestone with localized dolomitization, and karst fractured-vuggy reservoirs. Currently, on the gas source, hydrocarbon accumulation process and control factors in the Sichuan Basin during the Permian are lacking. To bridge this gap, herein, we identified the filling sequence minerals inside the pores/vugs, along with the oil charge of the Maokou Formation using drill cores, thin sections, oil inclusion analysis, and U-Pb dating of calcite cements. The results showed that the reservoir space of the Maokou Formation was predominated by the residual dissolved pores/vugs, fractures, and dissolved fractures. The pores/vugs underwent four stages of mineral filling by very fine-fine (-crystalline, CC1) calcite → fine-medium calcite (CC2: from 256.4 ± 1.7 to 244.1 ± 6.3 Ma) → fibrous calcite (FC; ∼183.9 ± 8.2 Ma) → coarse-macro calcite (CC3; ∼171.5 ± 5.3 Ma). Combined with the homogenization temperature and salty of fluid inclusion, we considered that three stages of oil charge were present in the Maokou Formation reservoirs. The first stage involved the formation of paleo-oil reservoirs during the Late Permian to Early Triassic, corresponding to the high-maturity aqueous inclusions in CC2, with a homogenization temperature of 106.7°C–137.8°C. At that time, the oil generation from the Lower Cambrian Qiongzhusi Formation rocks peaked, and the generated hydrocarbons migrated upward into the Maokou Formation through the strike-slip faults in the basin center. The second stage involved the formation of paleo-oil reservoirs during the Early Jurassic. The Permian source rocks reached the oil generation window with hydrocarbon expulsion, which was consistent with the oil inclusions in FC. The third stage involved the formation of paleo-gas reservoirs during the Middle Jurassic to Early Cretaceous, corresponding to the high-density methane inclusions and bitumen inclusions occurring in CC3, with the homogenization temperature peaking at 151.9°C–178°C. The natural gas in the Middle Permian of the Central Sichuan Basin is predominantly sourced from the Lower Cambrian Qiongzhusi Formation mudstone and partially from the source rocks of the Middle Permian, indicating a significant source-reservoir conduit of the strike-slip faults in the basin center. The findings provide considerable baseline data to advance further research in the Sichuan Basin.

Petroleum System Analysis and Burial History of Middle Permian Source Rock in Turpan–Hami Basin, NW China

The pre-Jurassic in the north depression of the Tuha depression is the most favorable replacement strata to obtain new reserves in the Turpan–Hami Basin. (Pre-Jurassic, in this paper, refers to the Permian and Triassic.) The main source rocks are the Taodonggou Group, of which the burial history and hydrocarbon generation potential remain unconfirmed. The investigation of the burial and thermal history is vital for the basin analysis and hydrocarbon exploration. Therefore, in this paper, by using the acoustic time difference method, vitrinite reflectance method, stratigraphic trend method and PetroMod-1D software, the differential characteristics of denudation thickness, burial history and thermal evolution history of different tectonic units in different periods of Taibei Sag in the Turpan–Hami basin are studied, and their influence on the petroleum system is analyzed, and then the zones with exploration potential are optimized. The results show that the Taibei Sag has experienced multiple tectonic uplift events. The Late Indosinian movement has profound effects on the Taodonggou Group source rocks. The rather large uplift amplitude postpones the maturation of source rocks. In addition, the Turpan–Hami Basin is a typical cold basin. Therefore, the thermal maturity of the source rocks is relatively low, with respect to the relatively deep burial. The thermal histories of the different sub-sags in the study area are slightly differentiated from each other. The Taodonggou Group source rocks in the Taibei Sag generally became mature during the Mid–Late Jurassic epoch, except for those in the Central–Southern Shanbei sub-sag, represented by Well LT-1, which reached the mature stage during the Late Triassic epoch. The study area has well-developed reservoir rocks, and effective reservoir bodies are formed in the slope zone and near the Tainan Sag, due to the higher porosity and permeability of reservoir rocks. The statistics related to the faults and an analysis of the structural styles of oil reservoirs indicate that the structural slope and anticline of the Huobei, Lianbei and Shanbei sub-sags are favorable for increasing reserves and production of hydrocarbons.

Present-Day Geothermal Regime and Thermal Evolution of the Fukang Sag in the Junggar Basin, Northwest China

The Fukang Sag in the Junggar Basin is an important petroleum exploration and exploitation region. However, the geothermal regime and tectono-thermal evolution of the Fukang Sag, which control its hydrocarbon generation and conservation, are still controversial. This study involved a systematic analysis of the present-day geothermal gradient, heat flow, and thermal history of the Fukang Sag for better further exploration. According to the well log data and well-testing temperature data, we calculated that the geothermal gradient of the Fukang Sag ranges from 16.6 °C/km to 29.6 °C/km, with an average of 20.8 °C/km, and the heat flow ranges from 34.6 mWm−2 to 64.3 mWm−2, with an average of 44.6 mWm−2. Due to the basement relief, they decrease from northeast to southwest. The weight averages of the single-grain apatite (U-Th)/He ages of the core samples are 1.3–85.2 Ma, and their apatite fission track ages range from 50.9 Ma to 193.8 Ma. The thermal modeling results revealed that the Fukang Sag experienced late Permian, late Jurassic, and late Cretaceous cooling events (although the timing and magnitude of these events varied among the samples), which were related to the continuous compression of the Junggar Basin. In addition, basin modeling indicated that the heat flow of the Fukang Sag decreased from 80 mWm−2 in the Carboniferous to the current value of 44.6 mWm−2. The Fukang Sag’s edge exhibits prolific hydrocarbon generation in the Carboniferous–Permian source rocks, while the Jurassic source rocks within the sag also undergo abundant hydrocarbon generation. This study provides new insights into the present-day geothermal field and tectono-thermal evolutionary history of the Fukang Sag, which are significant in terms of regional tectonic evolution and oil and gas resource assessment.

Petroleum in the Jurassic Reservoirs within the Eastern Fukang Sub‐depression, Junggar Basin, NW China: Correlation and Source Rock

AbstractThe origin and source of the petroleum in the Jurassic reservoirs within the eastern Fukang sub‐depression were geochemically investigated. They show thermal maturities matching the peak generation stage, while the condensates are at the early stage of intense cracking. Oils and condensates may have experienced mild evaporative fractionation, while mixing of severely biodegraded with non‐biodegraded oils has occurred. Using biomarkers and isotopes, petroleums were classified into Group I, II and III genetic groups, with Group III further divided into IIIa and IIIb subgroups. Group I petroleum displays heavy carbon isotopes, a strong predominance of pristine over phytane, high C19 and C20 tricyclic and C24 tetracyclic terpanes, low gammacerane, and dominant C29 steranes, while Group II shows light carbon isotopes, a predominance of phytane over pristine, high C21 and C23 tricyclic with low C24 tetracyclic terpanes, high gammacerane and dominant C27 steranes. Group IIIa petroleum shows mixing compositions of Group I and II, while Group IIIb displays similar compositions to Group I, but with significantly higher Ts, C29Ts and C30 diahopane proportions. Oil‐source rock correlation suggests Group I and II petroleums originate from Jurassic and Permian source rocks, respectively, while Group IIIa are mixtures sourced from these rocks and IIIb are mixtures from Jurassic and Triassic source rocks.

Prediction of oil and gas occurrence in the Vilyui hemisineclise according to interpretation of geological and geophysical data and basin modeling (Republic of Sakha (Yakutia))

The paper is aimed at the prediction of oil and gas occurrence of the Upper Permian, Lower Triassic and Lower Jurassic deposits in the Vilyui hemisineclise. The basin modeling research implies the Upper Paleozoic and Mesozoic petroleum system model of the Vilyui hemisineclise. The initial generation time at the bottom of the Permian source rock is 270 Ma. The most intense generation of hydrocarbons is found to be in the late Permian and early Triassic. The generation power of the Permian source rock is 800 trillion m3. The hydrocarbon losses is up to 90% in consequence of unfavorable seal properties of the Lower Triassic and Lower Jurassic clay formations. All the potential hydrocarbon traps of the Vilyui hemisyneclise are considered to be formed during the Cretaceous stage of development. There is therefore an appropriate environment for the hydrocarbon accumulation to be in progress. The interpretation of geological and geophysical data identifies the areal extent prediction of sand reservoirs and overlying clay interlayers of high quality in the Upper Permian and Lower Triassic seals. The goal of a comprehensive approach to the sedimentary basin research is to divide the territory into oil and gas zones of various prospects in relation to the factors controlling hydrocarbon deposits.

Vertically transferred overpressures along faults in Mesozoic reservoirs in the central Junggar Basin, northwestern China: Implications for hydrocarbon accumulation and preservation

Abnormally high pressure (overpressure) is common in oil reservoirs of the Mesozoic formations in the central Junggar Basin. However, the generation mechanisms of overpressure are still uncertain, which not only affects safe drilling implementation, but also restricts the understanding of hydrocarbon migration and accumulation. Based on measured pressures and mud weights, the pore pressure distributions in the Mesozoic formations are characterized in detail. The different generation mechanisms of overpressure in mudstones and sandstones are investigated based on logging responses and basin modeling. Finally, the significance of reservoir overpressure to oil accumulation and leakage is discussed. The results indicate that overpressure in the Mesozoic reservoirs in the central Junggar Basin is mainly developed below 4500 m, the excess pressures are between 12 and 58 MPa, the pressure gradient ranges from 12 to 21 MPa/km, the pressure ratios range from 0.6 to 0.95, and the overpressure ratios are between 0.25 and 0.91. The high-overpressure in reservoirs is mostly present in isolated sand bodies that are hydraulically connected to Permian source rocks by faults. The overpressure data corresponding to a pressure gradient of 11–14 MPa/km plot on the loading curve, showing typical disequilibrium compaction overpressure. The points with pressure gradients greater than 14 MPa/km obviously deviate from the loading curve, indicating unloading overpressure mechanisms. The logging responses and numerical simulation results confirm that the overpressure in mudstone is mainly generated by disequilibrium compaction and chemical compaction, and hydrocarbon generation has a limited contribution. The unloading overpressure in the sandstone is mainly generated by the vertical overpressure transfer process from the deep Permian overpressured compartment. The vertical transfer of overpressure is often related to oil migration and accompanied by high oil saturations. However, high-overpressure presents challenges for the sealing capacity of caprocks. Hydrofracturing or the activation of preexisting faults due to high overpressure determines the risk of seal failure, which controls hydrocarbon leakage. The research is of great significance for understanding the mechanisms of hydrocarbon migration along faults and evaluating caprock integrity in similar basins.

Hydrocarbon generation and expulsion of the Fengcheng Formation in the Mahu sag, Junggar Basin, China: Implications for shale oil resource potential

The Permian source rocks in the Junggar Basin are widely developed, especially the Fengcheng Formation, which is the most significant source rock in the basin. However, due to insufficient research on the hydrocarbon generation (HG) and hydrocarbon expulsion (HE) characteristics of the source rocks, it is unclear whether a significant amount of retained hydrocarbons remain within shales. In general, the original organic matter abundance and kerogen type control hydrocarbon generation potential (HGP) and HE capacity in lacustrine shales. Therefore, the degradation rate method was used to establish the original organic carbon recovery model for different types of kerogen. Combined with the geologic and geochemical characteristics of the source rock, the HG, HE, and shale oil resource potential of the Fengcheng shale have been evaluated. We have found that the Fengcheng shale is mainly carbonate-type mudstone widely distributed with an average thickness greater than 100 m. The Fengcheng shale is composed of type II kerogen and reached the mature to high-mature thermal maturity stage, with the maximum original organic carbon exceeding 4.0 wt%. Meanwhile, the amount of retained hydrocarbons within shales is abundant according to the HGP model. Monte Carlo simulation finds that the shale oil resources of the Fengcheng shale are 23.30 × 108 t. Free oil resources account for 60%, reaching 13.75 × 108 t, indicating tremendous shale oil exploration potential.

Origin of Mesozoic Biodegraded Crude Oils from the Eastern Chepaizi Uplift (Junggar Basin) Constrained by the Biomarker Recovery Method

The Mesozoic (Jurassic and Cretaceous) sandstone reservoirs in the eastern Chepaizi Uplift of the Junggar Basin (NW China) have become hot targets in recent years for their substantial amounts of oils discovered. However, the oil origin has been a controversial issue due to biodegradation. In this study, hierarchical cluster analysis and principal component analysis show that the Mesozoic crude oils can be divided into three oil families (A1, A2, and A3). Meanwhile, the biodegradation level of the three oil families (PM 6 to 9+) was evaluated based on the PM scale and the parameter-stripping method of strongly resistant parameters. Allowing for this extremely high biodegradation case, this study adopted a biomarker recovery method to recover the original appearances of the three oil families. Here, eight parameters related to hopane (H), tricyclic terpane (TT), and C24-tetracyclic terpane (C24 Tet) were recovered, the dispersion of eight parameter sets is significantly reduced, and the geochemical characteristics are more obvious, especially for TT. Thus, this reliability and robustness, as well as the similarity between the source rock and the biodegraded crude oils, encourage us to perform oil–source correlation. The oil–source correlation revealed that family A1 was derived from the Permian source rocks in the Shawan Sag, family A2 was mainly derived from the Permian source rocks in the Shawan Sag and mixed with a small amount of oils generated by the Jurassic source rocks in the Sikeshu Sag and the Carboniferous source rocks in the Chepaizi Uplift, and family A3 mainly originated from the Permian source rocks in the Shawan Sag mixed with a small amount of oil produced by the Carboniferous source rocks in the Chepaizi Uplift. This conclusion is also further supported by effective biomarker parameters and a stable carbon isotope (δ13C), discriminant analysis, hydrocarbon migration, and restored paleogeomorphology. The parameter recovery is evidenced as one of the most useful methods and showed higher resolution than the conventional oil–source correlation to identify the origins of biodegraded oils.

Overpressure origins and evolution in deep-buried strata: A case study of the Jurassic Formation, central Junggar Basin, western China

Overpressure is significant to the exploration and exploitation of petroleum due to its influence on hydrocarbon accumulation and drilling strategies. The deep-burial hydrocarbon reservoirs of Jurassic strata in the central Junggar Basin are characterized by intensive overpressure, whose origins are complex and still unclear. In this study, Bowers’ method and sonic velocity-density crossplot method based on well logging data were used as a combination for overpressure judgements in geophysics. Furthermore, the corresponding geological processes were analysed in quality and quantity to provide a rational comprehension of the overpressure origins and the model of overpressure evolution and hydrocarbon accumulation processes. The results showed that hydrocarbon generation in the Jurassic source rocks led to overpressure in the mudstones, while hydrocarbon generation in Permian source rocks led to overpressure in the sandstone reservoirs in Jurassic strata by vertical pressure transfer. The burial and thermal history indicated that the aquathermal effect of pore fluids by temperature increase in deep strata is also an important origin of overpressure, while disequilibrium compaction may not be the dominant cause for the overpressure in deep-buried strata. Furthermore, the continuous tectonic compression in both the north–south and west-east trends from the Jurassic period to the present may also have enhanced the overpressure in deep strata. Meanwhile, the developed faults formed by intensive tectonic compression led to pressure transfer from source rocks to the Jurassic reservoirs. Overpressured geofluids with hydrocarbons migrated to sandstone reservoirs and aggravated the overpressure in the Jurassic strata. To conclude, the intensive overpressure in the central Junggar Basin is attributed to the combination of multiple mechanisms, including hydrocarbon generation, the aquathermal effect, tectonic compression and pressure transfer. Furthermore, the developed overpressure indicated hydrocarbon migration and accumulation processes and the potential of oil and gas reservoirs in deeply buried strata. We hope this study will provide a systematic research concept for overpressure origin analysis and provide guidance for petroleum exploration and exploitation in deep-buried strata.

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

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

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

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

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

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

Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China

In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.

Origin and re-Os geochronology of vein bitumen in the Nanpanjiang basin, SW China: Implication for the ore-forming age of Carlin-type gold deposits

The Nanpanjiang basin has the second-largest concentration of Carlin-type gold deposits in the world. Although significant progress has been made during the past two decades, the age of gold mineralization has not been well constrained. Field observation shows that these gold deposits are spatially associated with hydrocarbon reservoirs. At the Lannigou gold deposit, solid bitumens exist as films within structural fractures and cut through the orebodies, indicating that these bitumens formed after gold mineralization. In this work, we systematically studied bitumen reflectance (Rb), trace element, carbon isotope, and Re-Os isotopic compositions. These results show that these bitumens have high Rb values ranging from 2.40 to 2.71, indicating that they are high-maturity pyrobitumen. Trace element analysis reveals that bitumens in the deposit have high V/Ni, V/(V + Ni), and Zr/Sc ratios, but low Ni/Co, La/Sc ratios, and exhibit relatively flat rare-earth element (REE) patterns with no obvious Ce or Eu anomalies, comparable to the corresponding elemental ratios and REE patterns of Permian source rocks in the region. These bitumens also have similar δ13C values (-24.4 ‰ to –23.8 ‰, mean = -24.1 ‰) to the Permian source rocks (–22.4 ‰ to 24.7 ‰, mean = –23.6 ‰), indicating that they originate from the Permian source rocks. Five bitumen samples cut through the orebody yield a well-defined isochron age of 173 ± 6 Ma, indicating that the Lannigou gold deposit formed before this time. Our new data, combined with previously published geochronological data, suggest that the majority of Carlin-type gold deposits in the Nanpanjiang basin were mineralized at late Triassic to early Jurassic. The Re-Os data of this study also imply that the bitumen Re-Os chronometer has a large potential to constrain the timing of metal mineralization in low-temperature hydrothermal deposits.

Application of biomarker recovery method for oil–source correlation in severe to extreme biodegradation in eastern Chepaizi Uplift, Junggar Basin (NW China)

Biodegradation always alters the original characteristics of biomarkers, thereby limiting the identification of heavy oil sources. The eastern Chepaizi Uplift is a typical heavy oil-producing unit in northwestern China, most of heavy oils were discovered in Lower Neogene Shawan Formation, Lower Cretaceous Tugulu Group, and Upper Carboniferous Xibeikulasi Formation, the source of heavy oils is a controversial issue. This study adopted a biomarker recovery method based on the quality conservation principle that uses the sum of the mass of the residual biomarkers and their corresponding biodegradation products to obtain the mass of the original biomarkers. The 25–norhopane and the 17–nortricyclic terpane homologs, which were detected in severely to extremely biodegraded oils in the Chepaizi Uplift, while the corresponding hopanes (H) and tricyclic terpanes (TT) were eliminated, which are therefore an excellent option for biomarker recovery. A total of 13 relevant parameters were selected for recovery, the results indicated that the effect is particularly notable: the standard deviations of the tricyclic terpenes-related parameters (for example, (C20+C24) TT/(C23+C24) TT) and the hopanes-related parameters (for example, C30H/G (Gammacerane)) were 0.258–0.268, 0.400–0.540 before the parameter recovery, then they changed to 0.174–0.260, 0.176–0.273 after the parameter recovery, which indicates the dispersion of those parameter sets are significantly reduced and them numerical characteristics are more clearly highlighted. And the recovery result shows that the characteristics of 13 parameters are more consistent with the Carboniferous source rocks in this region and the Permian source rocks in Shawan Sag, indicating genetic affinity of heavy oil with these source kitchens. The reliability of oil source determination was verified using the stepwise discriminant analysis method and stable carbon isotope discrimination. Therefore, we believe that the biomarker recovery method is an effective method for oil–source correlation of heavy oil and can help deep oil exploration in biodegradation regions.

Main factors controlling hydrocarbon accumulation in the Northwestern Sichuan Basin

The basin-mountain transition regions of foreland basins are hot spots for hydrocarbon exploration worldwide, while the complex geological features and hydrocarbon accumulation rules make hydrocarbon exploration very difficult. The Northwestern Sichuan Basin is a typical case where the unclear distribution rules restrict the further exploration of natural gas. In this study, geochemistry and seismic profile data were comprehensively used to reveal the main factors controlling hydrocarbon accumulation in the Northwestern Sichuan Basin. The Lower Cambrian and the Upper- Middle Permian source rocks have different carbon isotope compositions, indicating that they have different kerogen types, sapropelic kerogen for the Lower Cambrian source rocks, mixed kerogen for the Middle Permian source rocks and humic kerogen for the Upper Permian source rocks. The Northwestern Sichuan Basin can be divided into the unfaulted belt, the thrust front belt and the thrust nappe belt. The thrust nappe belt develops many large thrust faults, and the natural gas there mainly originates from the Lower Cambrian source rocks. However, due to different denudation of regional caprocks, hydrocarbons in the area adjacent to the Longmen Mountain fold-and-thrust system were destroyed, while in the area adjacent to the thrust front belt, they had good preservation conditions. The thrust front belt and the unfaulted belt develop a few or few thrust faults, and the natural gas there mainly originates from the Upper-Middle Permian source rocks and has good preservation conditions due to no denudation of regional caprocks. The distribution of thrust faults controls the natural gas origins in different areas, and the preservation conditions determine whether the gas reservoirs can survive to the present. These conclusions can provide guidance for natural gas exploration in the Northwestern Sichuan Basin and other basin-mountain transition regions in foreland basins worldwide.

Natural gas accumulation conditions and exploration prospects of the Middle Permian Qixia Formation in the Sichuan Basin

Exploration of natural gases in the Middle Permian Qixia Formation has achieved a breakthrough in the central and western Sichuan Basin since 2010. This study discusses the quality of dolomite reservoirs and source rocks, trap types and hydrocarbon charging history and proposes that good accumulation conditions are the basis for the large-scale enrichment of natural gas in the Qixia Formation. The high-quality reservoirs in the Qixia Formation are dolomites that primarily occur along platform margins and in the inner-platform shoals surrounding the Caledonian palaeo-uplifts. The Qixia gases originated mainly from the Cambrian and Permian mudstone source rocks. The overlaying Permian source rocks and the underlying Cambrian source rocks are both widely distributed and could provide sufficient gases for dolomite reservoirs. Additionally, the structural or structural-lithologic traps formed by an overlap of the Qixia dolomites and structurally high are favourable for oil and gas accumulation. The Qixia Formation had experienced four episodes of oil and gas charging from the middle-late Triassic to the Early Cretaceous, and traps located in structural-high zones are most favourable for hydrocarbon accumulation. Thus, the Qixia Formation has excellent accumulation conditions for the formation of large-scale gas fields. The concealed structural belts in the footwall of fault No. 1, the Longmenshan–Daxingchang structural belts and the periphery Gaomo–Shehong palaeo-uplift are the key zones for large-scale gas exploration in the Qixia Formation. The Qixia Formation is an important strategic replacement field for natural gas exploration in the Sichuan Basin following the Ediacaran Dengying Formation and the Cambrian Longwangmiao Formation.

Sulfate sources of thermochemical sulfate reduction and hydrogen sulfide distributions in the Permian Changxing and Triassic Feixianguan formations, Sichuan Basin, SW China

The sulfate sources of thermochemical sulfate reduction (TSR) and hydrogen sulfide (H2S) distributions in the Permian Changxing (P2c) and Triassic Feixianguan formations (T1f) in the Sichuan Basin were investigated using geochemical and carbon isotopic data for gases, and sulfur isotopic data for solid bitumen, H2S, and anhydrite. The concentration of H2S (>5.0%) is relatively high, and the δ34S values of the H2S are significantly higher than those of the Permian source rock kerogen, suggesting a TSR origin for the H2S. The δ13C values of the methane and ethane do not increase as the gas souring index (H2S/(H2S+∑Cn)) increases, and the δ34S values of the H2S are significantly lower than those of the solid bitumen, suggesting mainly liquid hydrocarbon dominated-TSR. The δ34S values of the solid bitumen and H2S in the Puguang gas field in the eastern platform are significantly lower than those in the Yuanba gas field in the western platform, and the sulfates for the TSR were most likely derived from the Early and Late T1f evaporative seawater, respectively. The sulfates required for TSR were most likely enriched during dolomitization based on the positive relationship between the H2S concentrations and the thickness of the dolostone reservoirs. The H2S distributions were mainly controlled by the sulfate distributions and the paleo-oil accumulations. The edges of the eastern and western platforms in the Kaijiang-Liangping trough, which were favorable for dolomitization and paleo-oil accumulations, are the most likely H2S-enriched areas in the Sichuan Basin.

Nanomechanical characterization of organic-matter maturity by atomic force microscopy (AFM)

Characterizing the thermal maturation of organic matter is essential to oil and gas resource evaluation and generation mechanisms, but is extremely challenging in nanoscale vitrinite-dominated formations (few suitable vitrinites in micron scales for traditionally microscope petrographic analyses), forming a critical issue in oil and gas geochemistry requiring new solutions. Here we considered Permian source rocks in the Junggar Basin, China, as a case study for the application of a new method for characterizing maturity based on nanomechanical properties. Atomic force microscopy (AFM) was used to characterize the nanomechanical properties of vitrinite at different maturity levels, and the results were combined with a micro-Fourier-transform infrared (FTIR) study to examine the chemical structural response to changes in mechanical properties. The Young's modulus of vitrinite increases in an S-shaped trend with maturity, reflecting differences in chemical structure at different evolutionary stages. In the early stage of maturity (< 0.7% Ro), vitrinite is relatively soft with a heterogeneous mechanical structure. On reaching the oil-generation threshold (∼0.7% Ro), the removal of aliphatic structures leads to a significant increase in Young's modulus. At the oil-generation peak (∼1.0% Ro), the Young's modulus increase slightly. When the vitrinite enters the gas window (> 1.3% Ro), the higher aromatization level results in a high Young's modulus, with mechanical structure becoming more homogeneous. The results show that maturity can be effectively characterized on the basis of the nanomechanical properties of vitrinite. This method has unique advantages in determining the maturity of organic matter with vitrinites being dominated by nanoscale particles, which cannot be easily measured by conventional microscopes. Thus, the AFM method is a useful supplement to the traditional vitrinite reflectance measurement.