•Bitumen in the Lower Cambrian giant gas reservoir of the Sichuan Basin was studied.•We found oil bitumen co-existing with solid bitumen in the reservoir.•The bitumen was derived from both Lower Cambrian and Lower Silurian shales.•The gas migrated from the underlying Neoproterozoic reservoir along faults.•Cambrian–Ordovician reservoirs at the top of Cambrian strata are exploration targets.Natural gas in the recently discovered Lower Cambrian Longwangmiao giant gas reservoir of the Sichuan Basin in southwestern China has been considered to be from oil-cracking and sourced from the underlying Lower Cambrian Qiongzhusi shales, similar to the underlying Neoproterozoic Dengying giant gas reservoir. However, geological considerations and differences in geochemistry between the Longwangmiao and Dengying gases/bitumens imply different scenarios. Organic petrology, geochemistry and trace element analyses of widely occurring bitumen were conducted to evaluate this hypothesis. Results show the coexistence of solid bitumen and oil bitumen in this reservoir for the first time, which implies a new hydrocarbon accumulation process and associated exploration strategies. The two types of bitumen were termed Type A solid bitumen and Type B oil bitumen, which were sourced from the Lower Cambrian Qiongzhusi Formation shale and the Lower Silurian Longmaxi shale, respectively. The Type A solid bitumen shows little fluorescence and its color under plane-polarized light is almost black. This indicates that the Type A solid bitumen is likely of high maturity. It typically occurs in dissolution pores, and accounts for approximately 90% of all bitumen in the reservoir. In contrast, the Type B oil bitumen is brown–black in color under plane-polarized light, and yellow–green under fluorescence light, indicating that it is mature. It occurs in the residual spaces of the solid bitumen, and represents approximately 10% of the total bitumen content. This suggests that Type A bitumen charged the reservoir earlier than did the Type B bitumen. During the Indosinian Epoch of the Triassic, oil generated from the mature Qiongzhusi Formation migrated into the Longwangmiao and Dengying reservoirs. Following this, the Dengying reservoir reached the temperature threshold for oil cracking since the Late Cretaceous, and it is suggested that oil could have started to crack to gas, which is the critical moment for the gas formation. However, the Longwangmiao oils had not been cracked at this stage because the reservoir temperature had not reached the threshold. Later, during the Himalayan Epoch, the gas in the Dengying reservoir, as well as some kerogen-cracking gas from the Qiongzhusi shales, migrated into the Longwangmiao reservoir along faults. Gas gravity drainage and phase separation took place in the Longwangmiao reservoir, forming the Type A solid bitumen and giant gas accumulation. Later, oil generated from the Longmaxi shales migrated into the Longwangmiao reservoir, forming the Type B oil bitumen. The case here is an example of a multi-stage oil and gas accumulation. Future exploration targets should include Middle–Upper Cambrian reservoir rocks.

•Hydrocarbon resource potential of Lower Cretaceous shales in Tibet is good.•Gas dominance is due to type II kerogen and high maturity.•Shales with TOC > 4.0 wt% may have unconventional hydrocarbon potential.•Shales were deposited in platform–lagoonal settings.Lower Cretaceous black shales have recently been discovered in the Qiangtang Basin (especially in its northern basin), Tibet, implying a new interval with hydrocarbon resource potential in the region. This potential, however, has not been investigated to date and is addressed in this paper based on organic petrology and geochemistry data from the representative Shengli River outcrop. Organic petrology, including optical and scanning electron microscope observations, indicates that the organic matter (OM) within these shale sequences has precursors from abundant benthic algae, some bacteria and amorphous OM and a few land plants, suggesting that the black shales were deposited in a generally reducing platform–lagoonal environment favorable for OM preservation. The shales have high total organic carbon (TOC) contents (1.74–7.71 wt%), type II kerogen (tending to type III), and high thermal maturity (vitrinite reflectance equivalent of ca. 1.3 %Ro). Biomarkers in the shales suggest deposition under reducing brackish or saline water with aquatic benthic organisms, bacteria and amorphous OM as the dominant input. Thus, the results of organic petrology, organic geochemistry and biomarker geochemistry are generally consistent and imply that the Shengli River black shale samples have significant hydrocarbon resource potential and most likely produced gas due to relatively high maturity and gas-prone kerogen. The neighboring black shales within the same stratigraphic interval as the Shengli River shales, if having moderate OM maturity and oil-prone kerogen, can be expected to generate oil. The presence of well-developed micropores and fractures, and abundant brittle minerals within the black shales suggests that they may have unconventional hydrocarbon resource potential, especially in intervals with high TOC > 4.0 wt%. These results provide new data and understanding for regional hydrocarbon exploration.

•Highly mature hydrocarbon–source correlation based on elemental geochemistry.•PAAS-normalized REE patterns, redox- and provenance-sensitive elemental ratios.•Trace and REE geochemistry of Sinian–Paleozoic paleo-oil reservoirs in South China.•Hydrocarbon source, accumulation and alteration in Sinian–Paleozoic paleo-reservoirs.Understanding the relationships between migrated hydrocarbons and source rocks under highly mature conditions (i.e., pyrobitumen–source correlation) is a critical and challenging issue in the field of petroleum geology and geochemistry. Based on a case study of three Sinian–Paleozoic paleo-oil reservoirs from Yunan and Guizhou provinces, South China, we attempt to provide further understanding of this issue using trace and rare earth element (REE) geochemistry, which can characterize the depositional setting, organic input and rock provenance of source rocks. Results show that the bitumens from the three paleo-oil reservoirs can be distinguished from each other using ‘Post-Archean Australian Shale (PAAS)’-normalized trace element distribution patterns, REE distribution patterns, hierarchal cluster analysis of element concentrations and redox- and provenance-sensitive elemental ratios (e.g., V/Ni, Ni/Co, Ni/Mo, Zr/Cr, La/Sc and La/Co). Pyrobitumen in the Devonian Xiaocaoba paleo-oil reservoir is derived primarily from Devonian source rocks, representing a self-sourced petroleum system and one stage hydrocarbon charging. Similarly, pyrobitumen in the Sinian Jinsha–Yankong paleo-reservoir also received a single fluid charge, but the source is different and likely generated by contributions from both lower Cambrian and Sinian sources. In contrast, the bitumen in Ordovician Kaili–Luomian paleo-reservoirs are indicated to have contributions from two different hydrocarbon sources and thus experienced two stages of hydrocarbon charging: an early charge from lower Cambrian source rocks and a later charge from Permian source rocks. The new trace and rare earth element method used in this study appears to be effective at providing a better understanding of the hydrocarbon–source correlation under highly mature conditions. The results improve our understanding of the complex hydrocarbon accumulation–alteration evolution in the marine strata of South China, which is a potential target for petroleum exploration.

•A better separation of hydrocarbons using reversed-phase column of GC × GC/TOFMS than normal column.•Reversed-phase column system is especially effective in separating low-molecular-weight hydrocarbons.•Biomarkers calculation benefits from the high resolution of reversed-phase column of GC × GC.Two-dimensional gas chromatography/time-of-flight mass spectrometry (GC × GC/TOFMS) is quite effective to analyze organic compounds in crude oils with high resolution and normal-phase column condition (non-polar/polar) was commonly used. Here, to improve the understanding on this method, based on Chinese oil samples, we analyze hydrocarbon fractions in the oils using GC × GC/TOFMS with reversed-phase column system (polar/non-polar) in addition to the normal-phase column system. Results show that the reversed-phase column system is more effective in separating saturated hydrocarbons than normal-phase column system. It is especially effective in generating two-dimensional spectra, because the compounds have a higher separation among different series (polarities). The reversed-phase column system is also particularly effective in separating weakly polar to non-polar saturated hydrocarbons (e.g., branched alkanes and naphthenes of low-to-medium molecular weight). It is also suitable for the isolation and identification of conventional biomarkers such as isoprenoids, steranes, and terpanes. Overall, in the GC × GC/TOFMS analysis of crude oils, the reversed-phase system has distinct advantages over the normal-phase system and specific compounds were identified in detail. Thus, this method deserves more attention. These results and understandings add new knowledge to oil geochemistry and have general implications.

The organic maceral suberinite is widely believed to be a contributor to immature or low mature oils with Ro < 0.5% in some coal and terrigenous sequences. However, its evolution of hydrocarbon generation, especially in the relatively high maturation stage of Ro > 0.5%, has not been sufficiently characterized. This issue was addressed herein using periderm cork tissues of the modern angiosperm Quercus suber (suberin), which is a possible bio-precursor of suberinite, in artificial bacterial degradation and hydrous pyrolysis experiments. Integrated studies were conducted, including analyses on the compositions of hydrocarbon yields and the content variations that were generated during the experiments, gas chromatography (GC) analyses of generated oils and spectral fluorescence observations, and Rock-Eval and Fourier Transform Infrared (FTIR) microspectroscopic studies on solid residues. Analytical results indicate that suberin and suberinite have long and complex hydrocarbon generation histories. In general, the hydrocarbon that is generated during bacterial degradation is predominantly gas and present in relatively limited amounts, while the oils mainly are generated during hydrous pyrolysis. Furthermore, the oil generation has two peaks that correspond to Ro of approximately 0.35–0.50% and 0.80–1.10%. In composition, the early generated oil mainly consists of long chain waxy and oxygen containing compounds, while the late generated oil is relatively enriched in aromatic compounds. These features can be ascribed to the chemical nature (e.g., composition and structure) of suberin. It is a type of insoluble and high molecular weight polyester compound that contains large quantities of long chain structure dicarboxylic acids and alcohols. Consequently, the deoxygenization of these compounds can take place under relatively low thermodynamic conditions, generating liquid oil that is dominated by a long chain structure and oxygen-containing waxy compounds. In contrast, the degradation of the phenolic compounds results in the second oil generation peak. Therefore, suberinite has a two stage and relatively long oil generation history and is a good bio-precursor for coal-derived oil generation.Highlights► We performed artificial bacterial degradation and hydrous pyrolysis experiments on suberin. ► The hydrocarbon evolution of suberinite was addressed based on the experimental data. ► Suberinite has a two-stage and relatively long oil generation history. ► Suberinite is a good bio-precursor for the immature and low mature coal-derived oil generation.

The petroliferous central Junggar Basin in northwest China is predominantly an oil exploration region. However, its gas exploration also might have good prospects. Thus to assist in gas exploration, the geochemistry and origins of gases are discussed in this paper based on relatively comprehensive analyses of compositions, carbon isotopes and light hydrocarbons of gases. Based on the results, the gas genetic types are grouped into families and combined with the geological setting (e.g., biomarkers of retrograde condensates and source rock characteristics). We show that there are four representative genetic types of gases. The first consists of gases derived from Permian lacustrine mudstones with type I–II kerogen and type III kerogen sources in the Penyijingxi sag. Their representative geochemical feature is δ13C2 ranging from −31.4‰ to −24.7‰. The second is gas sourced from Carboniferous tufaceous mudstones of type III kerogen in the Dishuiquan sag, whose representative geochemical feature is the heaviest values of δ13C1 in the studied samples, ranging from −32.0‰ to −30.4‰. The third consists of gases sourced from Jurassic coals and mudstones in the Shawan–Fukang sag. The light hydrocarbon fingerprints of these gases are similar to those of gases and oils typically derived from Jurassic source rocks in the southern Junggar Basin. The fourth is gas most likely generated from the degradation of crude oil. It is mainly found in the Luliang area and has dryness values as much as 0.999 and δ13C1 ranging from −54.8‰ to −43.2‰. Among these four types of gases, the first (mainly sourced from the Permian lacustrine mudstones in the Penyijingxi sag) is the predominant type.Highlights► Comprehensive gas geochemistry in the central Junggar Basin was reported. ► Gases are mostly middle mature and have complex origins with four genetic types. ► Gases derived from sapropelic and humic kerogens were found with a certain mixing. ► Gases most likely sourced from oil degradation were found.

25-Norhopanes have been found for the first time in Jurassic organic-poor mudstones in the northern Qaidam Basin (northwestern China). The carbon number distribution in the m/z 177 mass chromatograms does not consist of the full suite from C28 to C34, although this is a well-known feature generally ascribed to 25-norhopanes in source rocks. The ranges of C29 25-norhopane/C29 30-norhopane and C29 25-norhopane/C30 hopane are 0.07–0.08 and 0.03–0.04, respectively. These values are within the recognized global background level for 25-norhopane concentrations in source rocks [Blanc, P.L., Connan, J., 1992. Origin and occurrence of 25-norhopanes: a statistical study. Organic Geochemistry 18, 813–828]. Here, we provide additional evidence for the existence of 25-norhopanes in mudstones/source rocks. They were not detected in organic-rich mudstones, implying that the accumulation or diagenesis of the organic-poor mudstones may have provided the right conditions for the formation of 25-norhopanes. The depositional setting is suggested to be anaerobic and distant from the lacustrine lakeshore, based on biomarker and petrological features and previous sedimentary environment studies. In such a nutrient limited environment with relatively low source organic matter, microbial reworking of biomass occurred – microbial consortia scavenged the existing hopanoids, contributing biomass and releasing nutrients to perform 25-norhopane-forming reactions.

•Organic geochemical identification of reservoir oil–gas–water layers.•Conventional distinguishing standards vary in different regions.•GOI parameters were utilized for the first time in the Junggar Basin.•Gas and heavy oil layers could be identified by biomarkers.The identification of reservoir oil–gas–water layers is a fundamental task in petroleum exploration and exploitation, but is difficult, especially in cases of complex hydrocarbon migration and accumulation. In such cases, hydrocarbon remigration and dysmigration take place very commonly, leading to the presence of residual or paleo-oil accumulations and layers, which cannot be easily identified or misinterpreted as oil layers by conventional logging and geophysical data. In this paper, based on a case study in the Luxi area of the central Junggar Basin, NW China, we seek to characterize such layers in terms of organic geochemistry. We suggest specific indicator parameters of organic geochemistry such as the chloroform bitumen content of reservoir extracts, which is usually >1.0% in oil layers. We explore the application of grains containing oil inclusions (GOI) (the ratio of mineral grains containing oil inclusions to the total number of mineral grains) for the identification of oil–gas–water layers in the Junggar Basin for the first time; this method has been used elsewhere. The maximum GOI values for the oil layers, oil–water layers, water layers and dry layers are >11%, 7%–11%, 6%–7% and <6%, respectively. In addition, gas layers and heavy-oil layers that are difficult to identify by conventional organic geochemical parameters were identified using biomarkers. The typical characteristics of the soluble reservoir bitumen in the gas layers include a much greater abundance of tricyclic terpanes (two times in general) relative to pentacyclic terpanes and a tricyclic terpane distribution of C20 > C21 > C23. In contrast, the typical characteristic of the heavy-oil layers is the presence of 25-norhopanes in reservoir bitumen extracts. These specific indicators can be applied in the Junggar Basin and in similar settings elsewhere.

The well-known Ni–Mo ores hosted in early Cambrian black shales of South China are one of the research highlights in economic geology for the past few decades; however, their origin is complex and still debated. Here, based on a case study in the Huangjiawan ore of Zunyi City, Guizhou Province, we generate several new understandings regarding Ni–Mo mineralization through a comparative investigation of organic matter in metallic and non-metallic stratigraphic intervals, including abundance, type, maturity and relationship to mineralization. We find new direct evidence for biotic impacts on mineralization. Organic matter, and rhodophyte cystocarps (red algae) in particular, may be significantly correlated to mineralization, as it accumulates mineralized Ni and Mo. However, this organic material, as well as disseminated and amorphous organic matters, is not the sole and predominant factor controlling mineralization as implied from the nonlinear correlation between organic matter abundance/maturation and mineralization. Other fluid sources (e.g., hydrothermal and/or seawater) also contribute to mineralization, which may be influenced by hydrothermal activity. Ni and Mo may have mineralized independently, as suggested by their differential accumulation in different structures of the cystocarps, different relationships between organic matter abundance and thermal maturation and mineralized element concentration, as well as the large variation in element accumulation coefficients. The history of mineralization is complex, as Ni and Mo may be or not be deposited together during the same stage of mineralization. These results might also have broader implications for understanding the origin of sediment-hosted ores worldwide.

•Multiple-stage hydrocarbon charging events in central Junggar Basin are identified.•Primary and secondary oil accumulations.•Integrated oil-bearing fluid inclusion studies.The Permian lacustrine petroleum system in the central Junggar Basin, northwest China, has recently obtained exploration success. These accumulations are characterized by mixed oils and multiple-stage migration and accumulation. This process, however, has not been well constrained, limiting the understanding of the general laws of hydrocarbon migration and accumulation and making it difficult to define exploration strategies. Here, we reconstruct this process mainly based on oil-bearing fluid inclusion analyses including petrography, homogenization temperature and sequential extraction. Inclusion petrography shows that petroleum inclusions dominantly display yellow fluorescence, while intergranular free oils mostly display strong blue green fluorescence. This implies that the reservoirs seem to have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. The sources/maturities are determined through reservoir sequential extraction analyses. The free oils are mixed and sourced from the Lower Permian Fengcheng Formation (P1f) and the Middle Permian Lower Wuerhe Formation (P2w), while the inclusion oils are also mixed and derived mainly from the P1f source. Both oils are characterized by moderate maturity. Homogenization temperature measurements of oil-bearing fluid inclusions, combined with reconstruction of reservoir burial and thermal history, not only further verify multiple hydrocarbon charging events but also characterize the timing, which indicates a three-stage petroleum charging model. During the first stage of the Late Triassic, Carboniferous reservoirs were charged by P1f-sourced oils, which were dysmigrated or remigrated to Jurassic reservoirs during the second stage (i.e., the Early Cretaceous). In contrast, the third stage from the Late Cretaceous represents another hydrocarbon charge event that is the primary oil accumulation sourced from the P2w rocks. According to this model, both primary and secondary oil accumulations contribute to the current region's exploration success, and provide future exploration targets.

Petroleum exploration is increasingly extending from shallowly to moderately to deeply buried strata, with reservoir quality being a key. The formation mechanism of conventional clastic and carbonate reservoirs under such conditions has been widely investigated. However, the mechanism of mixed siliciclastic–carbonate reservoirs has not been well studied. In this paper, we address this issue using a case study in the northwestern Qaidam Basin, northwest China (N1–E1+2 age, 2500–4500 m). Dissolution pores and fractures dominate the reservoirs. However, only the fractures were the focus of previous studies. Thus, here we investigate dissolution and its impacts on reservoir formation, providing a complementary understanding of the reservoir formation in the basin. Using core observations and examining thin section, it was discovered that dissolution was both random and followed bedding. The dissolved components primarily included calcareous and gypsum minerals, with fingerprints that are characteristic of burial dissolution. Further electron probe analysis on authigenic minerals revealed that the dissolution fluid might have originated from acidic formation fluids associated with hydrocarbon generation. The fluids passed through faults and fractures. Dissolution pores were an important component of the reservoir, providing approximately 60% of the porosity. In addition, segments of high porosity generally above 5% are associated with dissolution. Based on these observations, a schematic model was established to explain the impacts of dissolution on reservoir formation. Specifically, organic acidic formation fluids enter tectonic fractures, resulting in dissolution as they pass through them. This dissolution enhances the size of the pore space and the reservoir properties of the rocks, eventually developing a fracture-dissolution reservoir.Highlights► Moderately to deeply buried reservoir characterized by mixed siliciclastic–carbonate deposition. ► Dissolution has important impacts on reservoir formation by enhancing properties. ► The dissolution is of burial origin, likely related to formation fluids associated with hydrocarbon generation. ► Dissolution has general significance for reservoir formation under moderately to deeply buried conditions.

Calcite veins and cements occur widely in Carboniferous and Permian reservoirs of the Hongche fault zone, northwestern Junggar Basin in northwest China. The calcites were investigated by fluid inclusion and trace-element analyses, providing an improved understanding of the petroleum migration history. It is indicated that the Hongche fault behaved as a migration pathway before the Early Cretaceous, allowing two oil charges to migrate into the hanging-wall, fault-core and footwall reservoirs across the fault. Since the Late Cretaceous, the Hongche fault has been sealed. As a consequence, meteoric water flowed down only into the hanging-wall and fault-core reservoirs. The meteoric-water incursion is likely an important cause for degradation of reservoir oils. In contrast, the footwall reservoirs received gas charge (the third hydrocarbon event) following the Late Cretaceous. This helps explain the distribution of petroleum across the fault. This study provides an example of how a fault may evolve as pathway and seal over time, and how reservoir diagenetic minerals can provide clues to complex petroleum migration histories.

•The Upper Jurassic–Early Cretaceous in the northern Qiangtang was deposited in a marine to brackish environment.•Redox conditions were weakly oxic to suboxic.•Temporal variations from marine to continental were revealed between shale, marl, and micrite.•Organic and inorganic geochemistry and petrology were presented.The Late Jurassic to Early Cretaceous depositional environments of the Qiangtang Basin in Tibet have the potential to provide significant insight into mechanisms of black shale deposition, organic matter accumulation, and the timing of closure of the Mesotethys Ocean. However, the depositional setting has not been well constrained. Here we apply multiple geochemical proxies and petrologic analyses to representative samples of black shale, marl, and micrite collected from a section in the region. These indicate a transitional marine–continental environment, with brackish to saline water. Redox conditions were weakly oxic to suboxic. Environments represented by the studied section varied over time. The lowermost marls were deposited in a low-salinity, weakly oxic shore to shallow lake environment, under a warm and humid climate regime. The micrites in the middle part of the section were deposited in a lagoonal environment, with intense evaporation, high salinity, and water column stratification. The uppermost shales were deposited in a reducing, semi-enclosed lagoon environment during a marine transgression. These results suggest that the Late Jurassic–Early Cretaceous succession was deposited in a tidal-flat or lagoonal environment.

•Origin of early Cambrian black-shale-hosted barite deposit in Dahebian, South China.•Mineralogical and geochemical comparison between ore and non-ore layers.•A generally restricted and reducing seawater basin environment.•Hydrothermal activity during mineralization focused in ore horizon.•First discovery of zoned hyalophane in Dahebian, South China.The barite deposits hosted in early Cambrian black shales in South China are a classic example of sediment-hosted stratiform barite deposits, and their origin is controversial. In this paper, we address the origin of these deposits by a comprehensive integrated study of mineralogy and geochemistry, based on a case study of the Dahebian deposit in Tianzhu County, Guizhou Province, which contains the largest global reserve of barite. Particular attention was paid to a comparison between ore and non-ore horizons, as this has not been fully addressed previously. The results indicate that the ore horizon is dominated by barite with intergrown hyalophane, quartz and pyrite. The hyalophane is zoned, implying hydrothermal activity. In contrast, the non-ore horizons contain minor amounts of granular barite and are free of hyalophane, suggesting that these horizons experienced weaker hydrothermal activity. The contrasting trace and rare earth element compositions of the ore and non-ore samples indicate dilution of complex geochemistry with multiple ore-forming processes and materials during barite mineralization. The barite mineralization was rapid, as demonstrated by the relatively low terrigenous input in the ore samples compared with the non-ore samples. The ore samples have positive Eu anomalies (>3.0), indicative of hydrothermal activity during mineralization. Organic geochemical analyses provide evidence of the development of abundant organic matter and hydrothermal activity. The sulphur isotopic values (δ34S) of the ore samples show an enrichment relative to contemporaneous early Cambrian seawater and substantial variation (+36.7‰ to +43.8‰), indicative of sulphur derived from seawater that was affected by sulphate-reducing bacteria and hydrothermal activity in a restricted marine environment. To summarize, the barite deposit in the Dahebian site was most likely formed in a generally restricted and reducing marine basin environment with rapid sedimentation during a period of hydrothermal activity. These results have general implications for the future study of other black-shale-hosted deposits worldwide.

The occurrence of a transgression in coastal southeastern China during the Early Cretaceous has been debated. This question was addressed here through the use of petrographic, paleontological and geochemical studies of ten representative Lower Cretaceous outcrop sections in the study area. The petrographic results suggest that limestones in the Shipu section of northeastern Zhejiang Province were predominantly deposited in a tidal flat environment. The paleontological study reveals marine red and brown algae in black shales and mudstones of the Yong'an and Chong'an sections of the western Fujian Province. In the biomarker study of black shales and mudstones, the widespread detection of gammacerane, in combination with ratios of tricyclic terpane C26/C25 < 1.3, hopane C35S/C34S > 0.8 and hopane C29/C30 < 0.8, demonstrates that the study area was influenced by a transgression. A carbon isotopic study provides additional evidence of the transgression, including positive carbon isotopes of the majority of calcareous mudstone and limestone samples (approximately 2.5‰), and correlation of the values between saturated (− 30.01‰ to − 22.87‰) and aromatic (− 29.42‰ to − 21.35‰) hydrocarbons of shale and mudstone samples. Thus, transgression did take place in coastal southeastern China during the Early Cretaceous, and was broadly simultaneous (from 119 ± 3 Ma to 99 ± 3 Ma) in different depositional regions based on zircon U–Pb dating. Under this isochronous framework, a paleogeographical limit of the transgression was tentatively proposed for the first time. The northern boundary extends at least to 29° N, whereas the western boundary is limited to the southeastern side of the Wuyi Mountains. Regional tectonic subsidence together with the overall high sea level may be the main driving force for the transgression. These results have broad implications for regional studies and for Cretaceous paleogeographical studies in general.Highlights► The K1 marine transgression event in coastal SE China was studied thoroughly. ► Evidence includes limestone/mudstone petrography, paleontology, δ13C and biomarker. ► The transgression time is from 119 ± 3 Ma to 99 ± 3 Ma based on zircon U–Pb dating. ► The northern boundary is approximately 29° N, while the western is southeastern Wuyi Mountains.