Formation Source Rocks Research Articles

Characteristics and Origin of Natural Gas in Yongfeng Sub-Sag of Bogda Mountain Front Belt

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ13C2 of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ13C1 of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II1. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

Tectonic evolution and source rocks development of the super oil-rich Bohai Bay Basin, East China

The Bohai Bay Basin, as a super oil-rich basin in the world, is characterized by cyclic evolution and complex regional tectonic stress field, and its lifecycle tectonic evolution controls the formation of regional source rocks. The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping, and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area. The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains: the Paleo-Asian Ocean, the Tethys Ocean, and the Pacific Ocean. It has experienced the alternation and superposition of tectonic cycles of different periods, directions and natures, and experienced five stages of the tectonic evolution and sedimentary building, i.e. Middle–Late Proterozoic continental rift trough, Early Paleozoic marginal-craton depression carbonate building, Late Paleozoic marine–continental transitional intracraton depression, Mesozoic intracontinental strike-slip–extensional tectonics, and Cenozoic intracontinental rifting. The cyclic evolution of the basin, especially the multi-stage compression, strike-slip and extensional tectonics processes in the Hercynian, Indosinian, Yanshan and Himalayan since the Late Paleozoic, controlled the development, reconstruction and preservation of several sets of high-quality source rocks, represented by the Late Paleozoic Carboniferous–Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks, which provided an important guarantee for the hydrocarbon accumulation in the super oil-rich basin.

Impact of Tethyan domain evolution on the formation of petroleum systems in the Sichuan super basin, SW China

Based on the “unidirectional break-up and convergence” geodynamic model, this study investigates the impact of the evolution of the Tethyan domain on the formation of petroleum systems in the Sichuan super basin and explores the enrichment pattern of natural gas. The results show that, firstly, the Sichuan Basin and its surrounding areas have experienced two unidirectional rifting-aggregation cycles triggered by the Proto-Tethys Ocean and the Paleo-Tethys Ocean during the Neoproterozoic to Triassic. During Jurassic–Cenozoic, the Sichuan Basin is incorporated in the circum-Tibetan plateau basin-mountain coupled tectonic domain system. The episodic tectonic movements within the plate control the sedimentary infill styles. Second, the evolution of the Tethyan domain, paleoclimatic environment and major geological events controlled the formation and distribution of high-quality source rocks within the basin. The rift valley and intracratonic rift, passive continental margin slope, and intracratonic sags are favorable areas for the development of source rocks. Third, the evolution of the Tethyan domain, supercontinent cycles, global sea level changes, and tectono-climatic events controlled the distribution of carbonate platform and reservoir-caprock combinations. The cratonic platform margins and sub-platform internal high terrains are key areas for finding carbonate high-energy facies belts. Syndepositional paleo-uplifts and surrounding slopes, regional unconformities, and later faults zone are areas where large-scale carbonate reservoirs are distributed. The regional evaporite or shale caprock are beneficial for the large-scale preservation of oil and gas in the basin. Fourth, the spatio-temporal matching relationship of reservoir forming factors influenced by the early tectonic-sedimentary evolution pattern and the degree of later tectonic modification is the key to oil and gas enrichment. Future oil and gas exploration should focus on potential gas systems during the Sinian rift period, Cambrian pre-salt gas systems in the eastern and southern Sichuan, as well as whole oil and gas systems of Permian and Triassic.

Accumulation sequence and exploration domain of continental whole petroleum system in Sichuan Basin, SW China

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source- reservoir relationship and accumulation model of the Upper Triassic–Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight–conventional gas in the Upper Triassic–Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas–conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources.

Hydrogen adsorption kinetics in organic-Rich shale reservoir rocks for seasonal geological storage

The geo-storage of hydrogen (H2) is essential for advancing a robust and industrial-scale H2-based economy. The efficient H2 storage in a geological formation depends on the presence of a secure and impermeable caprock, such as a shale formation. However, the existing literature lacks information on the kinetics of H2 adsorption in actual shale formations with diverse organic contents and mineral compositions. Therefore, the kinetics of H2 adsorption in organic-rich shale samples from a Jordanian oil (JO) source rock formation are experimentally investigated herein at various temperatures (193, 273, 303, and 333 K) and two equilibrium pressures (15 and 45 bar) by using a volumetric method. The impact of mineral compositions and total organic content (TOC) on H2 adsorption is studied using two samples with distinct mineralogy and TOC values. Thermodynamic calculations are performed, and common adsorption models are used to analyze the experimental data. The results indicate that the H2 adsorption rate increases with pressure and decreases with temperature, being characterized by an initial rapid adsorption phase followed by a slower adsorption period as the uptake of H2 approaches equilibrium. More interestingly, the rate of H2 adsorption is higher in the sample with a high TOC and a richer composition of carbonate minerals. Both the applied adsorption isotherm models and adsorption kinetics models fit the experimental data remarkably well, thereby indicating their suitability for analyzing the kinetics of H2 adsorption in the JO shale. The unipore model matches the H2 kinetics data well, with R2 > 0.91. The H2 diffusion coefficient increases with pressure and temperature, where the H2 diffusion in shale accelerates with thermal motion intensity. This study provides fundamental insights into the adsorption kinetics of H2 and is expected to assist in implementing an industrial H2-based economy.

Exploring the prospects of deep natural gas resources from the geochemical parameters of the Shahejie Formation source rocks in the Banqiao depression

Deep natural gas is an important field and direction for oil and gas exploration and development in the Banqiao depression. The geochemical characteristics of the Paleogene Shahejie Formation source rocks in the Banqiao Sag were investigated based on pyrolysis, Total Organic Carbon (TOC), chloroform bitumen A, vitrinite reflectance, saturated hydrocarbon gas chromatography–mass spectrometry, and maceral determination. The results showed that the Es3 source rocks of the Paleogene Shahejie Formation were generally of better quality than the Es1 source rocks. Regarding the Es1 source rocks, the abundance of organic matter was variable, with mixed types and low maturity. The source rocks were formed in a saline-water reductive environment. Regarding the Es3 source rocks, the abundance of organic matter was relatively high, meaning that they were of medium–high quality, with mixed types of, yet highly mature, organic matter. The hydrocarbon generation environment was oxidative, and the source rocks were mainly deposited in fresh water with localized salinization. The main hydrocarbon-generating components of organic matter in the Shahejie Formation were amorphous humic components formed by intensive microbial modification of lower planktonic algae and terrestrial higher plants. Aquatic organisms were the main sources of organic matter, with localized mixing of higher-plant organic matter. The organic matter derived from these higher plant debris sources provided beneficial conditions for the generation of natural gas. At present, the Shasan source rock is at the peak of hydrocarbon generation. Under deep conditions, the maturity of organic matter increases, and organic matter rich in terrestrial higher plants can make a significant contribution to the generation of natural gas, especially shale gas.

Detailed oil-source correlation within the sequence and sedimentary framework in the Fushan Depression, Beibuwan Basin, South China Sea

The Fushan Depression is one of the petroliferous depressions in the Beibuwan Basin, South China Sea. Previous studies have preliminarily explored the origin and source of crude oils in some areas of this depression. Nevertheless, no systematic investigations on the classification and origin of oils and hydrocarbon migration processes have been made for the entire petroleum system in this depression, which has significantly hindered the hydrocarbon exploration in the region. A total of 32 mudstone and 58 oil samples from the Fushan Depression were analyzed to definite the detailed oil-source correlation within the sequence and sedimentary framework. The organic matter of third member of Paleogene Liushagang Formation (Els3) source rocks, both deltaic and lacustrine mudstone, are algal-dominated with high abundance of C23 tricyclic terpane and C30 4-methylsteranes. The deltaic source rocks occurring in the first member (Els1) and second member (Els2) of the Paleogene Liushagang Formation are characterized by high abundance of C19+20 tricyclic terpane and oleanane, reflecting a more terrestrial plants contribution. While lacustrine source rocks of Els1 and Els2 display the reduced input of terrigenous organic matter with relatively low abundance of C19+20 tricyclic terpane and oleanane. Three types of oils were identified by their biomarker compositions in this study. Most of the oils discovered in the Huachang and Bailian Els1 reservoir belong to group A and were derived from lacustrine source rocks of Els1 and Els2. Group B oils are found within the Els1 and Els2 reservoirs, showing a close relation to the deltaic source rocks of Els1 and Els2, respectively. Group C oils, occurring in the Els3 reservoirs, have a good affinity with the Els3 source rocks. The spatial distribution and accumulation of different groups of oils are mainly controlled by the sedimentary facies and specific structural conditions. The Els2 reservoir in the Yong’an area belonging to Group B oil, are adjacent to the source kitchen and could be considered as the favorable exploration area in the future.

Prediction of Oil Source Fault-Associated Traps Favorable for Hydrocarbon Migration and Accumulation: A Case Study of the Dazhangtuo Fault in the Northern Qikou Sag of the Bohai Bay Basin

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es1L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es1L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es1L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es3 formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins.

The origin and migration laws of hydrocarbons in uranium‐bearing Luohe Formation, Pengyang area, SW Ordos Basin

The hydrocarbon activity in Pengyang area, situated in the southwestern Ordos Basin, is notably prominent. Investigation on the migration laws of hydrocarbons is imperative for comprehending the involvement in uranium mineralization. Based on the analysis of spatial distribution of hydrocarbon containing fluid and hydrocarbon generation conditions of sandstone in the Luohe Formation, the organic geochemical characteristics including hydrocarbon components, carbon isotopes and biomarker compounds were analysed. The research results indicate that: (1) hydrocarbon fluid activities in the Luohe Formation are predominantly observed in layers exhibiting higher uranium mineralization. The mudstone of the Luohe Formation had low organic matter content and low thermal maturity, which was not conducive to hydrocarbon generation. (2) Hydrocarbon‐containing fluid in the sandstone of Luohe Formation not only contained reducing gases such as methane and hydrogen but also chloroform asphalt components. The carbon isotopes of hydrocarbon in sandstone inform Luohe Formation resemble oil and gas in the Mesozoic. The biomarker parameter inferred that the parent rock of hydrocarbons in the Luohe Formation was formed under reducing and freshwater conditions, and hydrocarbon generation occurred at the mature stage. As above mentioned, a comparison was carried out between the affinity of hydrocarbon‐containing fluid in the Luohe Formation and different layers of hydrocarbon source rocks. The migration behaviour of hydrocarbon‐containing fluid in the Pengyang area has been summarized, and the involvement of hydrocarbon‐containing fluid in uranium mineralization has been discussed. The main concepts are as follows: the sedimentary environment and thermal evolution conditions of hydrocarbons in the sandstone of Luohe Formation resemble those of the primary hydrocarbon source rocks in the Yanchang Formation. The main hydrocarbon charging events in the Luohe Formation occurred before the Late Cretaceous period, which is primarily related to two hydrocarbon generation events from 130 to 100 Ma in the Yanchang Formation and fault conduits connecting the Triassic to the Cretaceous Strata. The hydrocarbon‐containing fluid released from Yanchang Formation migrating to the Luohe Formation provides reducing conditions for the precipitation of uranium in oxygen‐bearing water bodies.

PETROLEUM GEOLOGY OF THE CENOZOIC SUCCESSION IN THE ZAGROS OF SW IRAN: A SEQUENCE STRATIGRAPHIC APPROACH

The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW‐SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar‐Fars Arch. This sub‐division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono‐megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences.The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo‐Miocene Asmari Formation sealed by the evaporite‐dominated Gachsaran Formation, mostly contained within giant NW‐SE trending “whaleback” anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep.Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic‐rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas‐bearing structures in the Bandar Abbas region.

Differential enrichment mechanism of helium in the Jinqiu gas field of Sichuan Basin, China

Helium is extensively utilized in aerospace, healthcare, electronics, semiconductors, advanced science, and renewable energy sectors, playing a pivotal role in the advancement of human technology. Presently, helium is primarily extracted from natural gas as an associated resource. The cost of extraction decreases with an increase in the helium concentration within the gases. Therefore, understanding the mechanisms involved in helium generation, migration, and accumulation underground is vital. This article delves into the differential enrichment mechanism of helium in the Jinqiu gas field, situated in the Sichuan Basin of China, by analyzing the molecular and isotopic composition characteristics of the major gases and noble gases, employing gas dissolution and diffusion models. Compared with other Jurassic gas reservoirs in the Sichuan Basin, the Jinqiu gas field contains a significantly higher helium concentration, displaying unique enrichment patterns within its area. The majority of hydrocarbon gases originate from the local underlying Triassic Xujiahe Formation source rocks. Specifically, the western section of the Jinqiu field is primarily supplied by the higher maturity Xujiahe Formation source rocks located in the western Sichuan Basin. Notably, there is no significant contribution of mantle-derived volatile components in the Jinqiu field. Helium and argon are primarily radiogenic, whereas neon primarily originates from atmosphere. The good linear correlation between 4He and 20Ne suggests that their transfer is primarily facilitated through groundwater. The solubility calculation reveals that the helium exsolved from the in-situ pore water of the reservoir, due to stratigraphic uplift during the Himalayan movement, comprises only 0.04%–0.11% of the existing reserves. This suggests that gas desolvation plays a relatively minor role in helium enrichment in the Jinqiu field. Additionally, the calculation results of gas diffusion indicate that diffusion's contribution to helium enrichment in the Jinqiu gas field remains minimal. Finally, our analysis of methane reserve changes suggests that the combined effect of differential loss and dilution of hydrocarbon gases is the primary mechanism for helium's differential enrichment in the Jinqiu field. Notably, methane and carbon dioxide depletion may be a significant factor in helium enrichment within the crustal natural gas system.

Sources of natural gas in the Middle-Permian carbonate succession in the central-northern Sichuan Basin, Southwest China

Natural gas-source correlation is a challenging aspect of natural gas exploration in deep strata. The Middle-Permian carbonate succession in the Sichuan Basin, southwest China, particularly in the Maokou Formation, is a hotspot for natural gas exploration. However, determining the natural gas source in the Maokou Formation is challenging because of the high maturity and complexity of potential source rocks. In this study, we analyzed the genesis and sources of natural gas in the central-northern Sichuan Basin while considering the geological conditions and systematically utilizing the gas components, stable and rare-gas isotopes, and solid bitumen biomarkers. The results indicate that (1) the natural gas in the northern Sichuan Basin comprises a mixture originating from the source rocks of the Maokou and Wujiaping formations; (2) the Qiongzhusi Formation is the major source of natural gas in the north slope (and the Maokou Formation source rock could be used as an important supplement); (3) the natural gas in the Moxi-Longnvsi structure comprises a mixture originating from the source rocks of the Qiongzhusi and Maokou formations. From south to north and west to east, the major source rocks of the gas reservoirs changed from belonging to the Qiongzhusi Formation to the Maokou and Wujiaping formations. This study is the first to combine multiple geochemical methods and consider different geological settings to identify the gas source of a deep carbonate gas reservoir. Our study provides a reliable method for determining the natural gas-source correlation of gas reservoirs that contain highly mature and complex gas sources.

Tracing Oils and Gas Accumulation in Complex Petroleum Systems Based on Biomarkers, Light Hydrocarbons, and Diamondoids from Concomitant Crude Oils: A Case Study in the Shawan Sag of the Junggar Basin, NW China.

The Shawan Sag is one of the most promising blocks in the western Junggar Basin for natural gas and oil exploration. To date, the research and exploration degree here is still low, and there is limited understanding of the origin and migration of natural gas and oils, which seriously restricts future exploration and development. At least three oil charging episodes and one gas charging episode could be confirmed in the reservoirs on the western slope of the Shawan Sag based on the analysis of concentrations and ratios of hopanes and steranes, diamondoids, and light hydrocarbons. The first and second charging oils originated from the peak and late oil generation window stages of Lower Permian Fengcheng Formation (P1f) source rocks, respectively. The third charging oil originated from the late oil generation window stage of source rocks of the Middle Permian lower Wuerhe Formation (P2w). Combining the carbon isotopic compositions and the gas composition, the fourth charging gas was derived from the postmature source rocks of Carboniferous(C) and Lower Permian Jiamuhe Formation (P1j) and the high-postmature source rock of Lower Permian Fengcheng Formation (P1f). The preservation conditions of nature gas in the Mesozoic (T-K) cap rocks in the Shawan Sag, as indicated by methyladamantanes (MAs)/methyldiamantanes (MDs) ratio, are better than those in the Mahu Sag. In this study, the methyladamantane maturity parameters of oils in the reservoirs were proposed to evaluate the maturity and further determine the migration direction of late-charging natural gas. The results suggest that late postmatured natural gases were charged from the southern part to the northwest of the Shawan Sag. Therefore, the southeastern direction of Well SP1 is a favorable area for natural gas exploration in the Shawan Sag. Meanwhile the northern part of the sag is favorable for the exploration of high-mature oil generated from source rocks within the Middle Permian Lower Wuerhe Formation.

Investigation on the thermal maturity, organic matter sources and depositional environment of lacustrine source rocks in the Dongying Formation of the Bozhong Sag, Bohai Bay Basin, China

The unclear understanding of the source rock characteristics for the Paleogene Dongying Formation in the Bozhong Sag leads to the lack of cognition in oil and gas exploration. This research systematically evaluated the discrepancy in geochemical characteristics of source rock intervals in the Dongying Formation based on detailed analysis using Rock‐Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), maceral components, stable carbon isotopes and biomarker parameters. It discusses the organic matter sources, depositional environment, thermal maturity and hydrocarbon generation potential in the source rock intervals of the Dongying Formation. The organic matter abundance in the third member (E3d3) and lower sub‐member of the second member (E3d2L) of the Dongying Formation is higher, with an average TOC of 2.08% and 1.03%, respectively, indicating that these source rock intervals could have good and excellent quality. The source rocks of the Dongying Formation predominately contain exinite maceral group and type II1 and II2 kerogen. The thermal evolution is mainly in the low‐mature and mature stages. The organic matter sources in the Dongying Formation are mainly dominated by mixed origin (the carbon isotope reversal of aromatics also provides a potential explanation). However, the values of 1,2,5−/1,3,6‐trimethylnaphthalene, (1,2,5,6 + 1,2,3,5)‐tetramethylnaphthalene/tetramethylnaphthalenes, methyldibenzofuran/methylphenanthrene (MDBF/MP) and dibenzofuran/phenanthrene (DBF/PHEN) parameters in the E3d3 and some samples in E3d2L decipher relatively smaller values than other source rock intervals, proving the enhancement of the contribution of lower organisms. Moreover, the terrestrial input in the bottom‐up deposition process of the Dongying Formation gradually increases. The depositional environment reveals the Dongying Formation source rocks mainly developed freshwater sulphur‐poor lacustrine facies and shallow lake‐fluvial delta facies in an open clay‐rich sedimentary environment with poor water column stratification, belonging to the typical weak oxidation–reduction depositional conditions. The comprehensive geochemical evaluation concludes that the favourable supply of lower organisms and stable clay‐rich depositional environment in the E3d3 interval of the Dongying Formation are potential explanations for the formation of lacustrine source rocks with high organic matter abundance, intermediate thermal evolution and excellent hydrocarbon generation potential, providing a good foundation for the exploration and development prospects of hydrocarbons.

Geochemical Characteristic and Source Correlation of Biodegraded Oils from the Western Halaalate Area of Junggar Basin

The relationship between biodegraded oil and its source has long been a complex and contentious topic. The Western Halaalate area is located in the Piedmont area on the northwest margin of the Junggar Basin. Source rocks of the Fengcheng Formation exist both locally and in the nearby Mahu Depression. In order to determine the source of biodegraded crude oil in this area, the molecular marker characteristics of biodegraded crude oil were analyzed by gas chromatography-mass spectrometry. The results showed that the vitrinite reflectance (Ro) of source rocks of the Permian Fengcheng Formation in the nearby Mahu Depression is greater than 1.3% and has entered a high mature stage of condensate oil and moisture gas; the source rock of Permian Fengcheng Formation in Western Halaalate area is in a mature stage with Ro of 0.79%~1.13%. The ascending configuration of tricyclic terpenes C20-C21-C23 for the crude oil samples found in the Carboniferous strata of the Western Halaalate Area is consistent with the characteristics of the Fengcheng Formation source rocks, which are present in both the Western Halaalate Area and the nearby Mahu Depression. Chromatography spectrometry examination shows that crude oils have undergone a varying degree of biodegradation. The Carboniferous oil was originated from the in situ Fengcheng Formation source rocks based on the application of molecular markers resistant to biodegradation, such as maturity parameters, salinity parameters, the new gammacerane index, and aromatic hydrocarbon parameters, combined with the analysis of hydrocarbon migration pathway. In addition, the oil biodegradation alteration rules in the Western Halaalate area were clarified, which advances regional knowledge of the relationship between biodegraded oil and source rocks.

Theory-driven neural network for total organic carbon content estimation from well logs

Abstract Total organic carbon content (TOC) is a crucial geochemical indicator for assessing the hydrocarbon generation potential of source rock formations. Traditional TOC evaluation methods employing well logs do not match well with measured data in complex formations. While intelligent algorithms have the potential to improve TOC estimation accuracy, they have poor petrophysical significance. In this study, we develop the theory-driven neural networks (TdNN) to extend TOC prediction accuracy via combining logging mechanism models into the input of neural network. TdNN have two ways for merging petrophysical models with intelligent model, specifically TdNN based on series connection (STdNN) and based on embedded way (ETdNN). STdNN processes log responses through logging mechanism models and subsequently inputs them to the neural network for TOC evaluation. ETdNN inputs log responses and calculation results from logging mechanism models to the neural network to estimate TOC. Two ways achieve more accurate prediction results than ordinary neural network via improving the quality of input data, analogous to applying data augmentation methods on intelligent models. This study utilizes the Schmoker method, 𝛿logR method, and multivariate regression method as logging mechanism models of TdNN. The prediction performance of the proposed models is tested using data from two shale reservoirs in the Longmaxi Formation and the Shahejie Formation. Results show that the proposed ETdNN achieves the highest prediction accuracy, meaning that the ETdNN is suitable for predicting TOC of shale formations.

Response to palaeoclimate by Early Cretaceous terrestrial organic-rich shales in the Yin'e Basin: Evidence from sporopollen, n-alkanes and their compound carbon isotopes

The Cretaceous period is a typical representative of a ‘greenhouse climate’ in geological periods, and is also an important period for the formation of hydrocarbon source rocks, which has become a hot spot in the study of palaeoclimate and organic matter enrichment. In order to further explore the mechanism of action between paleoclimate and organic matter enrichment, the response mechanism of organic matter enrichment to palaeotemperature and palaeorainfall is finely characterised by synthesising the analysis of sporopollen, biomarkers and n-alkane carbon isotopes in this study. The sporopollen indicates that the palaeoclimate is generally temperate, semiarid to semihumid, and the n-alkane and n-alkane carbon isotopes indicate that the palaeoclimate and palaeorainfall have obvious fluctuations and synchronous characteristics of rainfall and heat. Based on the differences in palaeotemperature and palaeorainfall, the palaeoclimate can be further divided into three stages: cool-temperate and semiarid, warm and semihumid, and cool-temperate and semiarid. The trend of palaeoatmospheric pCO2 recovered from the carbon isotopes of normal alkanes C27, C29, and C31 is roughly the same as that of palaeotemperature, indicating that pCO2 is important in regulating palaeotemperature. According to the distribution pattern of organic carbon, different layers are divided into three sedimentary Units: I, II and III. Different sedimentary Units have good corresponding relationships with different palaeoclimatic stages. Under the cool-temperate and semiarid climate, lower palaeotemperature and higher palaeosalinity are not conducive to the prosperity of lake organisms. The formation of light grey mudstone, silty mudstone and carbonate has lower TOC, and the organic matter types are mostly II1 and II. Under a warm and semihumid climate, higher palaeotemperature and moderate palaeorainfall are conducive to the prosperity of lake organisms. The formation of oil shale and shale has higher TOC, and the organic matter types are mostly I and II1. However, excessive palaeorainfall brings much terrigenous debris, leading to the organic matter dilution. Therefore, palaeoclimate and palaeorainfall not only affect the abundance of organic matter, but also affect the types of organic matter. In the paper, the mechanism of organic matter enrichment is improved by delicately characterising the palaeotemperature and palaeorainfall.

Geochemical Characteristics of the Mallawa Formation, and its Relationship with the History of Source Rock Formation in the South Makassar Basin, South Sulawesi

A hydrocarbon system to determine the hydrocarbon potential in an area can be determined by the presence of three main components that ensure its existence together, one of main components are source rock. The South Makassar Basin has the potential to have a petroleum system that acts as a source rock for the Mallawa Formation. Source rock is a component of the petroleum system that has the ability to produce and store hydrocarbons, where this rock is generally a rock with fine grains such as coal or shale. Oil and gas exploration in Indonesia is a common thing because there are many prospect areas that have the potential to produce hydrocarbons. The South Makassar Basin is a Tertiary sedimentary basin of land type which is geographically located along West Sulawesi to South Sulawesi and this basin occurs due to tectonics or structures with high frequency. The South Makassar Basin was formed as a result of the expansion of the Makassar Strait which occurred at no younger than the Early Paleocene age where the tectonic consequences would influence the maturation process of the source rocks in the South Makassar Basin. Apart from that, in this research a geochemical method was carried out in the form of laboratory analysis to determine the maturity of the source rock using cuttings samples. So this research provides something new in the exploration of the maturity of source rocks, which in the South Sulawesi area has a complex tectonic setting.

Geochemical characteristics of Cambrian bitumen and Cambrian-Ordovician source rocks in the Keping area, NW Tarim Basin

The Cambrian Yuertus Formation and Ordovician Saergan and Yingan formation source rocks, which TOC contents of 0.38%–4.30%, are well developed in the Keping area of the Tarim Basin. Reservoir bitumen had been found in the Cambrian Wusongger Formation and Shayilike Formation. In this study, the geochemical characteristics of the bitumen and source rocks were analyzed through biomarkers for oil-source correlation. The results show that the characteristics of the bitumen and Yuertus Formation source rocks are similar. Comparatively, the Yuertus Formation source rocks and bitumen have lower Pr/Ph values and higher C28/C29 regular steranes values. The maturity characteristics and depositional environment of the Cambrian source rocks in the Keping area and the platform basin areas are similar. Plots of Ph/n-C18versus Pr/n-C17, Ts/(Ts+Tm) versus 4-/1-MDBT (methyl dibenzothiophene), and DBT/P (dibenzothiophene/phenanthrene) versus Pr/Ph distinguish the bitumen and source rocks well. As an original plot, we found that the Fla/Py (fluoranthene/pyrene) versus MP/P (methyl-phenanthrene/phenanthrene) intersection plot can be used to identify the possible sources of polycyclic aromatic hydrocarbons (PAHs) to a certain extent and can distinguish between the Cambrian and Ordovician source rocks in this study. Comprehensive analysis revealed that the bitumen samples most likely originated from the Yuertus Formation source rocks. It was also found that the biomarker characteristics such as the shape type of the C27-C28-C29 regular steranes, triarylosteranes, and triarylosteroids are not applicable to distinguishing the Cambrian and Ordovician source rocks in the Keping area. These research findings provide references for studying the Lower Paleozoic oil-source correlation in the platform in the Tarim Basin.

Preliminary Geochemical Appraisal on Sumatera, Java, and Kalimantan Coaly Source Rocks

In Western Indonesia’s petroleum system, one of the hydrocarbon source rocks was deposited in parallic-deltaic environment with high organic content, categorizing it as coaly source rock. This study focused on geochemical characteristics of 25 coal and coaly shale samples from rock outcrops and well representing the Central Sumatra, South Sumatra, South Central Java, Barito, and Kutai Basin, with additional data from previous studies. TOC analysis and Rock-eval Pyrolysis were carried out to reveal the geochemical characteristics and maturation pathway of the source rock. The TOC analysis results showed a value of 0.5-67.73 wt%, indicating poor-excellent source rock potential. Further rock-eval pirolysis exhibits kerogen type II/II-III (excluding samples from Ngimbang Fm.), with gas-dominated hydrocarbon. Hydrocarbon Index ranging from 4-308 mg/gC indicates possible low-moderate quantity of hydrocarbon that can be generated by the source rocks. Despite the overall fair-good source rock potential, Tmax of the samples indicates a very poor maturity level, with only Upper Talang Akar as the mature candidate. Thus, it can be concluded that young source rock candidates in Western Indonesia (limited to the basins studied in this research) initially possess potential in generating hydrocarbons, if it is not for the immature level of most coaly source rock formations.