Oil Source Rocks Research Articles

Organic geochemistry and 1D-basin modeling in the Taranaki Basin, New Zealand: Implications for deltaic-source rocks of the cenozoic oil and condensate reservoirs

The Taranaki Basin in New Zealand is an area of active exploration for oil and condensate. This research focuses on integrating geochemical characteristics and 1-D basin modeling to Late Cretaceous to Miocene source rock systems, along with oil and condensate data from fifty-seven wells in the Taranaki Basin. The geochemical study reveals that the oil and condensate samples were generated from clay-rich source rocks, containing mixed organic matter, with large amounts of terrestrial organic matter input. These source rocks were deposited in fluvial to fluvio-deltaic environments under oxic conditions. The presence of oleanane in both oil and condensate samples suggests that the source rocks had a significant terrestrial component and deposited during the Late Cretaceous to Cenozoic. Using various biomarker proxies, oil-source rock correlation along with 1-D basin modeling revealed that the oil and condensate were mainly derived from the Late Cretaceous Rakopi and Paleocene Farewell formations at different maturity stages. The oils were generated within the peak-mature oil window, while the condensates primarily resulted from the secondary cracking of oil taking place in the source rock within the gas generation window. This finding is consistent with the 1-D basin modeling results. The model shows that the Paleocene Farewell source rock has achieved the primary stage of oil generation (0.55–0.95 Easy %Ro), contributing to most of the discovered oils in the Cenozoic reservoir rocks. Meanwhile, the Late Cretaceous Rakopi source rock reached the gas window with a higher vitrinite reflectance of more than 1.30 Easy %Ro, indicating greater gas generation potential.

Evaluation of source rocks and prediction of oil and gas resources distribution in Baiyun Sag, Pearl River Mouth Basin, China

By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin, China, the development characteristics of hydrocarbon source rocks in the sag are clarified. Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type, scale, and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation. The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks, which are deposited in a slightly oxidizing environment. The source rocks are mainly composed of terrestrial higher plants, with algae making a certain contribution, and are oil and gas source rocks. Current geothermal field of the sag was reconstructed, in which the range of geothermal gradients is (3.5–5.2) °C/100 m, showing an overall increasing trend from northwest to southeast, with significant differences in geothermal gradients across different sub-sags. Baiyun Sag has undergone two distinct periods of extensional process, the Eocene and Miocene, since the Cenozoic era. These two periods of heating and warming events have been identified, accelerating the maturation and evolution of source rocks. The main body of ancient basal heat flow value reached its highest at 13.82 Ma. The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags. The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity, while the Eocene Enping Formation has reached the stage of maturity to high maturity. The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window. Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil, and has ability to generate kerogen cracking gas in the late stage. The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation. The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags, with an average of about 1 200×104 t/km2. Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3rd and 4th members of Wenchang Formation. Four favorable zones are selected for the division and evaluation of migration and aggregation units: No. ▪ Panyu 30 nose-shaped structural belt, No. ▪ Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt, No. ▪ gentle slope belt of Baiyun east sag, and No. ▪ Baiyun 1 low-uplift.

GEOCHEMICAL ANALYSES OF EOCENE OILS IN DEEPLY BURIED SANDSTONE RESERVOIRS IN THE DONGYING DEPRESSION, BOHAI BAY BASIN, NE CHINA

We report the results of organic geochemical analyses of 19 crude oil samples from reservoir sandstones in the 4th Member of the Eocene Shahejie Formation from wells in the Minfeng Sag, Dongying Depression, Bohai Bay Basin (NE China). In addition, 42 Shahejie Formation core samples of dark‐coloured mudstones, including 28 extracts, were analysed. Geochemical data included Rock‐Eval measurements, gas chromatography, GC‐MS and diamondoid analyses.Maceral analyses showed that mudstones in the 4th Member of the Shahejie Formation (“Es4”) contain Types I and II1 kerogen. The member can be divided into upper (Es4s) and lower (Es4x) intervals. Oil‐prone Es4s rock samples have good to excellent hydrocarbon‐generating potential based on calculated initial TOC values; Rock‐Eval Tmax values indicate that they are sufficiently mature for hydrocarbon generation. Analytical results suggest that both Es4s and Es4x mudrocks are potential source rocks for oils produced at fields in the Minfeng Sag.Analysed crude oils from the Minfeng Sag were classified into three genetic groups. Group I oils are mature to highly mature and have undergone a moderate degree of thermal cracking. They are characterized by a low β‐carotane/nC25 ratio and C30 4‐methylsterane index (4MI); high values of oleanane index (oleanane /C30‐hopane), C27 diasterane/C27 regular sterane (C27Dia/C27), regular sterane/17α hopane and gammacerane/C30 hopane (G/H); and medium pristane/phytane ratios (Pr/Ph). This suggests that Group I oils are mostly derived from source rocks in the upper part of the Es4x unit which are interbedded with evaporites. Group II oils are mature and have high 4MI and Pr/Ph ratios, low oleanane index, regular sterane/17α hopane and C27Dia/C27 ratios, and mediumβ‐carotane/nC25 and G/H. These features are similar to those of Es4s source rocks, indicating their genetic correlation. Group III oils show the lowest maturity and highβ‐carotane/nC25 and regular sterane/17α hopane, and low oleanane index, Pr/Ph and 4MI. Previously‐published data indicates that oils similar to those in Group III were mainly sourced by Es4s mudstones.

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.

Hydrocarbon potential and depositional environment of the Middle Miocene Balikpapan Formation, lower Kutai Basin, Indonesia: Sedimentology, calcareous nannofossil, organic geochemistry, and organic petrography integrated approach

The Middle Miocene Balikpapan Formation is exposed in the Samarinda Anticlinorium, which forms part of the Lower Kutai Basin situated on East Kalimantan, Indonesia. The Balikpapan Formation is considered the main source rock for oil and gas fields in Lower Kutai Basin. This study integrates sedimentology, organic geochemistry, organic petrography and calcareous nannofossil analysis to characterize the depositional environment, to determine the source of the organic matter, and to assess the hydrocarbon potential of the Balikpapan Formation. The studied sections contain at one locality calcareous nannofossil assemblages with low diversity including Sphenolithus heteromorphus, suggesting nannofossil zones NN4 – NN5 (upper Burdigalian - Langhian-lower Serravallian) are restricted to the Air Putih section in the northeastern part of the study area. Six facies associations were identified in the study area, comprising eleven lithofacies, interpreted as fluvial-deltaic to shallow marine in origin. The fine-grained lithofacies include shale, coaly shale and coal while the coarse-grained facies include sandstone and sandy conglomerates. The geochemical results (TOC) indicate that the analyzed samples have strongly varying total organic carbon (TOC) contents. The organic matter is composed of type III (gas-prone) and type II-III (mixed oil and gas prone) kerogen, with HI values ranging from 32 to 252 mg HC/g TOC. The Rock-Eval parameter Tmax 409–441 °C and vitrinite reflectance values (0.40–0.67 %Rr) indicate that the sediments are immature to marginal mature. The rank of coal in the Balikpapan Formation ranges from the sub-bituminous to the high-volatile bituminous B stage.

Oil families, oil–source rock correlation, basin modeling, and implication for petroleum systems, Termit Basin, Niger

Oil families, oil–source rock correlation, basin modeling, and implication for petroleum systems, Termit Basin, Niger

Application of Gaussian and Exponential Inversion for 2D Relaxation Maps in Source Rock Oil and Gas Reservoirs

Application of Gaussian and Exponential Inversion for 2D Relaxation Maps in Source Rock Oil and Gas Reservoirs

Sedimentology, depositional processes, and sequence stratigraphy of deep lacustrine fine-grained sedimentary rocks in the lower Oligocene Xiaganchaigou Formation, Qaidam Basin, Northwestern China

Lacustrine deep-water fine-grained sedimentary rocks are characterized by high heterogeneities in lithology and lithofacies stacking patterns, controlled by sediment supply and lake level fluctuation. Despite their vital roles as source and reservoir rocks of unconventional oil and gas play, depositional processes and sedimentary sequence of lacustrine fine-grained sedimentary rocks are poorly understood compared to their extensively studied deep marine counterparts. Here, we studied lithofacies, transportation and depositional processes, depositional environments, and sedimentary cycles of deep-water fine-grained deposits of the Lower Oligocene Xiaganchaigou Formation from cored wells in the western Qaidam Basin. Nine lithofacies that stack repetitively in 6–18 m thick sedimentary cycles are identified based on petrographic observation, geochemical analysis, and scanning electron microscopy. The regressive systems tract of a sedimentary cycle is composed of detrital-rich massive fine sandstone deposited by debris flows and thin-bedded fine sandstone deposited by high-density turbidity currents. The transgressive systems tract is dominated by laminated carbonate-rich mudrock facies deposited by low-density turbidity currents. A complete sedimentary cycle is interpreted to represent a transgressive-regressive cycle controlled by fifth-order lake-level variation. Coarse-grained detrital-rich debrite and high-density turbidite were deposited in the proximal sublacustrine fan and channel during lake-level regression, with sediments mainly supplied by terrigenous siliciclastic input. Carbonate-rich low-density turbidites are deposited primarily in the distal sublacustrine fan during lake-level transgression. Thin-laminated carbonate-rich mudrock facies with high organic matter abundance and well-developed laminae-induced fractures are considered both source rocks and target reservoirs of the upper Xiaganchaigou Formation.

Induced polarization of clay-rich materials — Part 3: Partially saturated mixtures of clay and pyrite

Source rocks for oil and gas are often associated with shales that are rich in pyrite and kerogen. Induced polarization is a suitable tool to characterize these formations. We develop a new experimental database of 43 laboratory experiments using mixtures of clay and pyrite under fully or partially water-saturated conditions. The liquid water saturation is in the range of 20%–100%, whereas the pyrite content is in the range of 0%–17%. Spectral-induced polarization measurements are performed in the frequency range of 0.1 Hz to 45 kHz at room temperature (approximately 25°C ± 1°C). The complex conductivity spectra are fitted with a Cole-Cole model, and the Cole-Cole parameters are determined using a stochastic procedure based on a Markov chain Monte Carlo sampler. The Cole-Cole parameters associated with low-frequency dispersion are then plotted as a function of the (water) saturation and pyrite content (volume fractions). Four predictions of the model are tested against the experimental data. We find that the model is able to explain the results, including (1) the chargeability depends on the pyrite content in a predictable way, (2) the (instantaneous) conductivity depends on the saturation according to Archie’s law, (3) the Cole-Cole exponent does not depend on the saturation and pyrite content (except at very small pyrite content of <1 vol%), and (4) the relaxation time is inversely proportional to the instantaneous conductivity. We also develop a more advanced petrophysical model using a double Cole-Cole distribution, in which one distribution is associated with the clay minerals and the other is associated with the pyrite.

Time and mechanism of formation of mud volcanoes in the South Caspian basin according to seismic data

There are 277 mud volcanoes located in the South Caspian basin and the Apsheron-Gobustan periclinal trough and the Lower Kura depression that open to it. On land there are 177 mud volcanic structures, from which steam, water, mud, gas and oil are constantly erupting at approximately 500 points. Mud volcanoes located in the Caspian Sea (about 100) also play an important role in the degassing (mainly methane) of the sedimentary layer of the earth’s crust. Based on the results of geological and geophysical research, it has been established that almost all mud volcanoes discovered on the territory of Azerbaijan are associated with hydrocarbon deposits. In the Oligocene – Lower Miocene, mainly in the Maikop time, a thick clayey stratum (Maikop) - source rocks – accumulated in the South Caspian depression. At the end of the Miocene, there was a sharp drop in erosion levels in this basin. As a result of the activity of several river systems (Pleo-Volga, Paleo-Kura, Paleo-Pirsagat, Paleo-Amu Darya) over the Maikop clay deposits, a system of alternating layers of low and high density was formed with a total thickness of sediments of eight kilometers or more. The Maikop clay formations buried under this multilayer system, possessing the properties of a non-Newtonian fluid, created intrusions in the overlying environment, which at subsequent stages of development of the sedimentation basin became eruptive channels of mud volcanoes. The results of research using 3D seismic data made it possible to identify the mechanism of formation of mud volcanism, which, according to the authors, is associated with the migration of hydrocarbons from oil and gas source rocks to reservoir rocks, with the channels of mud volcanoes being considered as the main migration routes. Geological interpretation of seismic data shows that the formation of mud volcanoes in the South Caspian basin supposedly began from the beginning of the Miocene and continued in parallel during subsequent periods of development of the sedimentation basin. As the thickness of the sedimentary cover increased, mud volcanoes periodically became active.

Geological structure and petroleum systems of the Kazakhstan sector of the Caspian Sea South Mangyshlak sedimentary basin

This article discusses the results of a study of the geologic structure of Mesozoic sediments in the Kazakhstan sector of the Caspian Sea South Mangyshlak sedimentary basin. This paper includes an analysis of existing geological and geophysical data aimed at describing the characteristics of petroleum system elements. The main features of the sedimentation conditions of oil source rocks, reservoirs, and caps have been analyzed. The key hydrocarbon source zones in the territory of the Kazakhstan sector of the Caspian Sea have been determined. The correlation of existing wells to determine regional covers and main trends in reservoir sedimentation has been provided.

Influence of geotemperature conditions on the oil and gas potential of the South Caspian depression (the case of the Lower Kura depression and Baku archipelago)


 
 
 In the article, the oil and gas potential of the deep-lying sediments of the Lower Received in revised form 13.08.2023; Kura depression and the Baku archipelago, which are geostructural elements of the South Accepted 13.11.2023 Caspian depression, are investigated according to the geotemperature conditions. The main aim of the research is identifying the oil-gas «windows» in the 22-24 km thick sedimentary rock complex of the South Caspian depression based on the geothermal factor. Using temperature values measured at different depth sections in different structures of the Lower Kura depression and Baku archipelago, temperature distribution maps of the area and a graph of changing temperature by depth were constructed. According to the geothermal maps constructed for the Lower Kura depression, a relatively high temperature value is observed in the north-west part of the area. This anomalous value is related to the location of active, periodically erupting mud volcanoes, which play an important role in temperature distribution, as well as local uplifts, which are more complicated by tectonic landslides and upthrusts. At great depths (5,500-6,500 m) within the research region, almost everywhere, anomalously high pore and reservoir pressures are observed, which create the conditions for the manifestation of tectonic-physical processes and the generation of great energy affecting the oil and gas potential of the area. In all the geotemperature maps constructed for different depth intervals in the Baku archipelago, high temperature values are observed in the north zone where the Sangachal-deniz-Duvanni-deniz-Khara-Zira island and Alat-deniz structures are located. This is due to the complication of uplifts by active mud volcanoes, which play an important role in the formation of local heat sources. The Khara-Zira island mud volcano, the largest in the Baku archipelago, is also located here. Based on the analysis of the temperature values in the research areas, a decrease in the temperature values is observed due to increase in the thickness and the clay content of the sedimentary layer in the direction from the Lower Kura depression to the South Caspian basin. The temperature is 990C at 5,000 m in the Lower Kura depression, 900C in the Baku archipelago. So, a decrease in temperature is characteristics for all depths. The analysis of the compiled graphs shows that the top of the main zone of oil formation in the Lower Kura depression starts at a depth of 2,000-2,500 m, and the lower limit is located at a depth of about 9,000 m (1500 C). The top of the main zone of oil formation in the Baku archipelago starts at a depth of 3,000 m, and the lower limit is located at a depth of 9,000-11,000 m. So, it shows that as the oil and gas formation sources the potential oil source rocks in the Lower Kura depression and the Baku archipelago at the depth range from 2,000-2,500 m to 8,000-11,000 m can produce industrially important oil and gas.
 
 

Exploitation and Utilization of Generated Oil and Gas by Pyrolysis Simulation Modeling of Shale Source Rocks under the Condition of In Situ Conversion

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock.

Advancements and research priorities in the field of Earth Science in the Republic of Sakha (Yakutia)

This article presents the significant findings of research in the field of Earth Science in the Republic of Sakha (Yakutia). The main focus of future research includes the investigation of the geological structure and evolution of the Earth’s crust in Yakutia, exploration of ore-forming systems for strategic mineral types, identification of oil source rocks, and the discovery of natural naphthide accumulations. These findings serve as a fundamental basis for enhancing the level of geological exploration of the subsurface, development of advanced technologies for geological exploration and prospecting in specific geological settings. It is essential to monitor the natural environment and climate of the region, establish a comprehensive system for observing, analyzing, and forecasting the response of ecosystem components to both natural and anthropogenic changes, and develop technologies for the restoration of disturbed areas. The recognition of the importance of ensuring a sufficient number of highly qualified staff members is also acknowledged.

About the source rock of therapeutic oil of the Naftalan field

About the source rock of therapeutic oil of the Naftalan field

Correlation Between Chang‐9 Crude Oil and Potential Source Rocks, Upper Triassic Yan‐Chang Formation, Middle Area of Ordos Basin: Correlation Between Crude Oil in the Chang‐9 Member and Potential Source Rocks

The Chang 9 oil layer deposits within Ansai District, Ordos Basin, yield considerable reserves of crude oil, yet their source remains ambiguous. This research endeavor was designed to characterize the Chang 9 crude oil and the Chang 7 and Chang 9 source rocks (SRs) of the Yan‐Chang Formation via organic geochemical analysis. The results indicate that the Chang 9 crude oil exhibits a Pr/Ph ratio of 0.84–2.29 and Ga/C30H less than 0.1, implying formed in a weak reduction to weak oxidation freshwater environment. The regular sterane C27‐C28‐C29 configuration assumes an inversed “L” type, reflecting mixed sources and dominant terrestrial plant input. Ratios such as C2920S/(20S + 20R) (0.54–0.6) and C29ββ/(ββ + αα) (0.44–0.58) indicate a mature oil stage. The depositional environment of the C7 and C9 SRs is similar, with weak oxidation to reduction conditions, and consists mainly of Type I and II organics, with a relatively higher maturity of the C9 SRs. A difference in C19/C23TT and C30D/C30H was found between the C7 and C9 SRs. The results show that the C9 crude oils have a similar C19/C23TT with the C9 SRs and similar diahopanes distribution with Class II SRs (C7 and part of the C9 SRs). Thus, the C9 crude oils most likely originate from the C9 SR mixed with the C7 SRs.

Structure and composition of the Sarailinsky depression oil source strata in territory of the Tatarstan Republic

The work carried out a study of core material from oil source rocks of the Sarailinsky depression, located between the southern and northern domes of the Tatar arch within the Tatarstan Republic. The well sections of the Sarailinsky strata are dominated by carbonate rocks, represented by packstones, wackestones and mudstones. Among the limestones lie interlayers of carbonate-siliceous rocks and mudstones. All rock lithotypes are enriched to varying degrees in sapropelic organic matter, which allows them to be classified as oil source deposits. There is a tendency for the relative content of organic matter to increase in the series: limestone → carbonate-siliceous rocks → mudstones. Judging by the interlayering of rocks of different composition in the section, the formation of the Sarailinsky strata took place in a marine sedimentation basin, with periodically changing environmental conditions. Under normal conditions, limestone was formed, under abnormal conditions, carbonate-siliceous rocks enriched in organic matter were formed, and when the removal of terrigenous material from the continent intensified, argillites were formed.

Palaeoclimatic influence on lake palaeoenvironment and organic matter accumulation in the Middle Jurassic Shimengou formation (Qaidam basin, NW China)

The formation and accumulation of lacustrine organic-rich shales are strongly related to palaeoclimate and palaeoenvironmental conditions. Middle Jurassic organic-rich lacustrine shales in the Qaidam Basin, NW China, are important source rocks for unconventional oil and gas exploration, but factors controlling their organic matter (OM) abundance and preservation are unclear. To understand how palaeoclimate and palaeoenvironmental conditions influenced depositional processes and elucidate the factors controlling OM accumulation of lacustrine organic-rich shales, we investigated total organic carbon (TOC), mineral compositions, and element geochemistry the Shale Member of the Middle Jurassic (J2s2) Shimengou Formation from the Yuqia Coalfield in the Qaidam Basin. From the bottom to the top, the Shale Member includes three significant stages based on their average TOC values of 5.45% (Stage I), 9.90% (Stage II), and 1.10% (Stage III). Paleoclimate proxies including C-values and Rb/Sr ratios indicate that in Stage I the lake developed under warm and humid conditions, while in Stage II climate changed to hot and arid/semiarid conditions before returning to warm and humid climates in Stage III. Correlation analysis among proxies for palaeoclimate, terrestrial influx (Al2O3 and TiO2 contents), sedimentation rate ((La/Yb) N ratios), palaeosalinity (Sr/Ba ratios and B/Ga ratios), palaeoproductivity (P/Ti ratios and Sibio contents), redox conditions (Corg/P ratios), and TOC values revealed that palaeoclimate had little direct impact on OM accumulation, with palaeoenvironmental conditions the main controlling factor for OM accumulation. OM accumulation in Stage I was primarily controlled by redox conditions, followed by palaeoproductivity, terrigenous influx, and sedimentation rate. In Stage II, high palaeoproductivity and anoxic bottom water conditions controlled OM accumulation, resulting in the deposition of oil shales with abundant hydrocarbon potential. In Stage III, poor OM preservation related to oxic redox condition was the primary controlling factor for OM accumulation. We suggest that variations in lake palaeoenvironments induced by palaeoclimate change controlled OM accumulation and petroleum potential.

FIRST RESULTS OF U−Th/He DATING OF EPIGENETIC PYRITE FROM ROCKS OF THE BAZHENOV FORMATION, WESTERN SIBERIA

U–Th/He method was applied to determine the age of epigenetic pyrite from the oil source rocks of the Bazhenov Formation, Western Siberia. Results indicate the possibility to date the post-sedimentation processes in a sedimentary basin by authigenic pyrite U–Th/He dating. The U–Th/He isochron age of pyrite (n = 7) from the dolomites of the Bazhenov Formation within the Frolovskaya megadepression is much younger than the age of sedimentation and corresponds to the Santonian-Cenomanian stages of the Upper Cretaceous (90 ± 8 Ma).

Multiple S-isotopic evidence for seawater incursions during the deposition of the upper Cretaceous source rocks in the Songliao Basin, northeastern China

The Songliao Basin, with an area of ∼260,000 km2 in northeast China, hosts the largest oilfield in China, which is one of the world's most productive oilfields. However, the origin of the organic-rich upper Cretaceous source rocks remains controversial. In this study, we report multiple S-isotopic compositions of pyrite (δ34S and Δ33S) from Member 1 (K2n1) and Member 2 (K2n2) of the Nenjiang Formation in the Songliao Basin. Our isotopic results reveal an extraordinarily large negative δ34S excursion of 50.54‰ (from +11.09‰ to −39.45‰), which is strong evidence for seawater incursions. The increasing positive Δ33S excursion coupled with the negative δ34S excursion strengthen the inference of a large influx of seawater to the Songliao Basin. We used a steady-state isotope box model to estimate the magnitude of the seawater incursions. Our modeling results show that the sulfate concentrations may have increased by 12–46 times when seawater invaded the Songliao Basin. We suggest that marine incursions may have facilitated the chemical stratification of the Songliao Basin and played an important role in the formation of the oil source rocks. Our findings potentially have important implications for understanding the formation of oilfields elsewhere.