Oil Source Rocks Research Articles

POTENTIAL SOURCE ROCKS EVALUATION FOR THE PRE-SALT COMPLEX OF THE EASTERN EDGE OF PRECASPIAN BASIN

Through basin analysis, the major tectonic stages and paleogeographic conditions of the formation of potential oil and gas source rocks of the subsalt complex of the eastern side zone of the Precaspian basin are considered. Prediction and localization of potential source rocks is critical for the Precaspian petroleum system understanding, both during petroleum play assessment at the prospecting and exploration stages. The generation and emigration potential of the oil and gas basin is determined not only by the concentration of the initial organic matter in the rock, but also by the type of kerogen. Based on Rock-Eval studies and comparative analysis with published biomarker data, the generation potential, genetic type and thermal maturity are analyzed depending on the age and structural relatedness of potential source rocks. A high generation potential has been established for the Lower Permian deposits, the occurrence of multiple generation foci controlled by the type and concentration of organic matter is predicted, which led to the formation of specific reservoirs of the "akzharite" type. The generation potential of the Visean-Bashkirian deposits is poor to average, catagenetic unconformities have been established within KT-II, KT-I, which indicates erosions, the total organic carbon (TOC) is 0.1-4%, the hydrogen index increases with depth, for samples enriched with TOC and with a content of S2 > 1, type II kerogen has been established, which it is an indicator of reducing marine environment. 2D basin modeling was performed in order to reconstruct the thermal evolution of potential source rocks and their thermal maturity and transformation ratio were modelled to determine the regional characteristics of hydrocarbon generation and migration. It is assumed that the formation and distribution area of the primary source rocks is associated with reducing conditions of the deep-sea shelf and continental slope and intensive subsidence in the Late Devonian-Lower Permian times. Conducting a comprehensive analysis of paleogeographic and paleotectonic conditions for the formation of potential source rocks is of key importance in the seismic interpretation and reconstruction of thermal history. 2D basin modeling was performed in order to reconstruct the thermal history of potential oil-producing strata and the degree of catagenetic maturity and the kerogen maturity index were estimated to determine the regional characteristics of hydrocarbon generation and migration.

Oil origin and migration direction in Wushi sag, Beibuwan Basin, South China Sea

The Wushi sag is one of the most important petroleum-bearing units located in the Beibuwan Basin, South China Sea. Insufficient understanding of oil origin and migration direction, and lack of characterizing oil differential accumulation distribution patterns in Wushi sag greatly restrict further hydrocarbon exploration. In this study, oil-source rock genetic relationships and migration directions were analyzed in detail by combining geochemical analysis of 45 source rock samples, 23 crude oil samples, 12 oil sandstone samples, and basin modeling results. The geochemical data show there is distinguishable heterogeneity in Liushagang Formation (Fm) source rock in Wushi sag, which is divided into two types. The first type (including the Member (Mbr) 23 and Mbr 3 of Liushagang Fm source rocks) was deposited in a weak reducing to suboxic and fresh to brackish water environment with a predominance of aquatic algal plankton input. The second type (including the Mbr 1 and Mbr 21 of Liushagang Fm source rocks) was deposited in a suboxic and fresh to brackish water environment with mixed inputs of aquatic algal plankton and terrestrial higher plants. Three groups of crude oils (A, B, and C) are identified using their physical properties and biomarker data. The group A oil is characterized by a higher abundance of oleanane, lower abundance of C30 4-methylsterane, higher values of Pr/Ph, and lighter δ13C values, and is mainly derived from the Mbr 21 of Liushagang Fm source rock. Group B and group C oils are characterized by a lower abundance of oleanane and higher abundance of C30 4-methylsterane, but present some differences in Pr/Ph and δ13C values. Both groups of oils are sourced from the Mbr 23 of Liushagang Fm source rock, and their differences in geochemical characteristics indicate the lateral heterogeneity of source rock. Oil migration directions are determined by combining maturity parameters, pyrrolic nitrogen compounds, and also basin modeling results. The preferential oil migration directions in Wushi sag are from the central to the northeast and south of the sag. The accumulation distribution of different groups of oils is mainly controlled by the vertical and lateral heterogeneity of Mbr 2 of Liushagang Fm source rock.

Stratigraphic Characteristics and Sediment-Filling Process of the Early Permian Fengcheng Formation in the Northwestern Margin of the Junggar Basin, Northwest China

The Permian Fengcheng Formation in the Mahu sag of the Junggar Basin is a crude oil reservoir and source rock. However, its stratigraphic characteristics, the boundary marks of the three members (lower, middle, and upper), and the sediment-filling processes are unclear. This study presents the sedimentary systems and sediment-filling processes in an intracontinental rift basin of this area using sedimentary-faces analysis, sequence stratigraphy, well logs, and two-dimensional seismic interpretations. The results show that the Fengcheng Formation consists of three third-order sequence stratigraphy (SQf1, SQf2, and SQf3). The lowest member of the Fengcheng Formation is composed of gray to dark gray thin middle layers of tuff, lacustrine dolomitic mudstone, and argillaceous dolomite near the depocenter. Tuff, siltstone, a small amount of fan–delta glutenite, volcanic breccia, and basalt are present near the fault zone. The logging curve is characterized by a high gamma-ray (GR) value, high amplitude, wavelength growth, and medium frequency. Near the depocenter, the middle member of the Fengcheng Formation comprises gray and gray–black thin layers of lacustrine muddy dolomite and dolomitic mudstone and thin sandstone and mudstone interbedded between tuff and gravel near the orogenic belt. The logging curve displays high-to-low GR values, high amplitude, short wavelength, and high frequency. The upper member of the Fengcheng Formation is not characterized by lesser tuffaceous and dolomitic components but by an increased fan–delta sandy content. Next, the bottom of the upper member is composed of lacustrine mudstone and siltstone interbedded between dolomitic mudstones; whereas, the top of the upper member is dominated by fan–delta coarse sandstone and sandy conglomerate. The logging curve shows low GR values, small amplitude, and continuous stability. The sediment-filling process of the Fengcheng Formation is controlled by fault activity. Overall, the lower and middle members of the Fengcheng Formation expand during the sediment-filling process of the lake basin of the Mahu sag; whereas, the upper member contracts. The strong uplift of the Horst near the Baiquan and Mahu orogenic belts led to an increase in provenance supply, resulting in a contraction of the southwestern margin of the lake basin during the sedimentation period from lower member to upper member of Fengcheng Formation.

Feasibility of Thermal Utilization of Primary and Secondary Sludge from a Biological Wastewater Treatment Plant in Kaliningrad City

Hydrothermal liquefaction (HTL) of sewage sludge is considered in the article as an analogue of the natural processes of oil formation (catagenesis). A comparison of the physicochemical composition of primary and secondary sludge with type II kerogen (natural precursor of oil) showed their similarity. Both types of sludge have a slightly higher level of oxygen and nitrogen. The study tested the hypothesis that the elements included in the inorganic part of the oil source rocks can have a catalytic effect on the oil formation processes. For the conducted studies of sludge HTL, the catalysts containing cations and substances found in oil source rocks were chosen: as homogeneous catalysts (KOH, NaOH, NH4Fe(SO4)2, CoCl6, NiSO4, CuSO4, ZnSO4, MoO3) and as heterogeneous catalysts (MgO, Zeolite, Al2O3). The effectiveness of catalysts containing metal ions, zeolite and aluminum oxide has been proven. The highest biocrude yield was achieved in a process with NiSO4 as the catalyst in a dose 2 g per 10 g of sludge: oil yield increased by 34.9% and 63.4% in the processing of primary and secondary sludge, respectively. The use of catalysts provided an increase in fuel HHV by 10.8–12.5%, which is associated with a decrease in oxygen content (by 10.8–43.2%) with a simultaneous increase in carbon (by 7.9–10.9%) and hydrogen (by 6.5–18.7%) content.

Organic geochemistry and petrology of source rocks from the Banqiao Sag, Bohai Bay Basin, China: Implications for petroleum exploration

The organic geochemistry and petrology of source rocks determine the hydrocarbon generation potential of the Banqiao Sag. In this study, organic geochemistry and petrology were used to determine the abundance of organic matter (OM), OM type, OM maturity, and sedimentary environments of the source rocks, collected from Cenozoic Shahejie Formation, Banqiao Sag, Bohai Bay Basin, China. Vitrinite and liptinite are the main maceral composition of the source rocks, and range from 18% to 81% and from 2% to 82% on a mineral matter free (MMF) basis, respectively. The values of vitrinite reflectance ( R o ) (0.36%–1.20%) and the T max values (397–486 °C) show that the thermal maturity range from low mature to peak-maturity. The abundance of OM varies between 0.22% and 4.37%, suggesting that the source rocks of the Shahejie (Es) Formation are mainly fair to good source rocks. The Rock-Eval pyrolysis results show that the source rocks have good petroleum generation potential. The amount of free hydrocarbons ( S 1 ) and hydrocarbons generated from pyrolysis ( S 2 ) range within 0.01–3.70 mg/g, and 0.04–29.17 mg/g. The hydrogen index (HI) varies between 18.18 and 741.13 mg HC/g TOC, with most of the samples appearing to be mainly Type II kerogen, and thereby exhibiting the ability to generate both oil and gas. The ratios of Pr/Ph, the cross plot of Pr/nC 17 –Ph/nC 18 , the cross plot of C 29 /C 27 –Pr/Ph, and ternary of dibenzothiophene, dibenzofuran, and fluorene, indicate that the Shahejie Formation deposited in suboxic and weak reducing environments. The main biological source is from advanced plants. The maceral composition and rock pyrolysis data indicate the kerogen type is a humic type or mixed sapropelic-humic type. The source rocks of the Shahejie (Es) Formation occur in the oil window, and the abundant organic richness, humic kerogen demonstrate that these rocks are effective oil and gas source rocks. The mudstone rocks in the Shahejie Formation are the main source of oil and gas and represent the main exploration target for the Banqiao Sag. This study enhances the great prospect of oil and gas production in the Banqiao Sag.

Uranium in Source Rocks: Role of Redox Conditions and Correlation with Productivity in the Example of the Bazhenov Formation

The paper reports comprehensive analysis of different factors affecting uranium content in oil source rocks and the relationship between uranium content and productivity of source rocks. The analysis of data for 13 wells of the Bazhenov Formation (Western Siberia, Russia) was carried out. The uranium content of the rocks was measured by gamma-ray spectrometry on core samples. In order to analyze factors affecting uranium accumulation in source rocks, we studied content and characteristics of organic matter (Rock-Eval pyrolysis), and also mineral, element, and isotope composition of rocks. We have shown that redox conditions at the sedimentation stage have the most pronounced impact on the uranium accumulation in the rocks of the Bazhenov Formation. It was also shown that productive intervals, containing increased amounts of mobile hydrocarbons, are characterized by low (<20 ppm) concentration of uranium. However, the intervals, containing phosphorite minerals may show better reservoir properties and oil saturation at higher concentration of uranium. The analysis of correlations and relationships between uranium content and Rock-Eval pyrolysis indexes (oil saturation index and productivity index) enabled formulation of criteria for selection of oil-saturated intervals using the spectral gamma and pulsed neutron spectroscopy log data.

The controlling effect of chair-shaped slope break landforms on sedimentation in continental faulted basins: A case study in the Xilinhaolai area, Baiyinchagan depression, Erlian Basin, China

To reveal the geomorphic characteristics of the gentle slope zone in a continental faulted basin and its control on sedimentary systems, we have performed the geomorphic units division and comprehensive analysis of seismic facies, well-log facies, and core facies in the Xilinhaolai area in the western area of the Baiyinchagan depression, North China. The results find that the gentle slope in the Xilinhaolai area developed a chair-shaped slope break, which includes four geomorphic segments: steep slope of the depression margin (SSDM), shallow-water gentle slope (SWGS), deepwater steep slope (DWSS), and depression center. The chair-shaped slope break controlled the distribution of the sand body by controlling the water depth and hydrodynamic type of sedimentation. The SSDM was a favorable place for the deposition of beach bars. It has become a good oil reservoir not only because of its shallow burial and good physical properties but also because of the location configured with stepped faults. On the SWGS, the active river current and lake waves caused the deposition of large-scale braided river deltas and shoal bars, which are already the main oil and gas areas discovered in the Xilinhaolai area. On the DWSS, a large-scale slump turbidite fan developed and became a very favorable oil and gas reservoir near the oil and gas source rock. The slumped turbidite fans on the DWSS and the shoal bar on the SSDM are potentially favorable reservoirs for future oil exploration.

Simultaneous thermal analysis method for studying the oil source rocks

Simultaneous thermal analysis method for studying the oil source rocks

Generation and emigration of hydrocarbons in the Meso-Cenozoic complex of the Black Sea-Caspian region

As part of the assessment of the prospects for oil and gas potential in the study area, numerical modeling of generation and accumulation systems was performed, as a result of which the centers of hydrocarbon generation located within sedimentary basins were identified. Based on the levels of modern maturity and OM transformation of the established and proposed oil and gas source rocks, as well as the estimates of the specific densities of hydrocarbon emigration at 5 stratigraphic levels, independent generation centers were identified: Middle Jurassic, Lower Cretaceous, Eocene, Maikop and Miocene. Variations in the sinking rates of basins at different stages of their development had a critical impact on the realization of their generation potential by oil and gas source strata. As a result, source rocks of the same age in the basins overcame the critical moment at different times and by now have realized their potential to varying degrees. In basins with low subsidence rates, there is a delay in the emigration process with respect to generation, which is not typical for basins with high rates. The main promising complex within the study area is Cretaceous deposits, the hydrocarbon saturation of which is provided both by its own source rock and by flows from deeper horizons of the sedimentary cover. The second most important are the Paleogene complex. Keywords: Black Sea-Caspian region; Meso-Cenozoic complex; cata-genetic zoning; modern maturity of deposits; degree of transformation of organic matter; generation; emigration; critical mome.

Application of machine learning algorithms in predicting pyrolytic analysis result

Introduction. Geochemical studies of organic matter in oil source rocks play an important role in assessing oil and gas accumulation in any territory. These studies play a particularly important role in forecasting unconventional resources and oil and gas reserves (so-called shale hydrocarbons). It is recommended to carry out pyrolytic studies by the Rock-Eval method for rocks saturated with organic matter on samples before and after their extraction with chloroform. However, extraction is a laborious and time-consuming process, and the load on laboratory equipment and the time required for analysis is doubled.Aim. To get a working model for predicting pyrolytic parameters of extracted samples, without carrying out extraction analysis.Materials and methods. In this paper, machine learning regression algorithms are applied for predicting one of the pyrolysis parameters of extracted samples based on the pyrolytic analysis results of the extracted and non-extracted samples. To develop the prediction model, 5 different machine learning regression algorithms were applied and compared, including multiple linear regression, polynomial regression, support vector regression, decision tree, and random forest.Results. The prediction result showcases that the relationship between the parameters before and after extraction is complex and non-linear. Some methods have shown their incompatibility with the assigned tasks, others have shown good and satisfactory results. Those algorithms can be applied to predict all geochemical parameters of extracted samples.Conclusions. The best machine learning algorithm for this task is the Random forest.

The Impact of Lamina Characteristics and Types on Organic Matter Enrichment of Chang 73 Submember in Ordos Basin, NW China

The Chang 7 member in Ordos Basin is an important shale oil exploration layer, with new shale-oil discoveries in recent years. The Chang 73 submember is rich in organic shale, which is the main source rock of shale oil in the Yanchang Formation. In order to clarify the lamina structure, composition, types, and distribution characteristics in Chang 73 submember and its influence on organic matter enrichment, a full coring well in Chang 73 submember located in deep-lacustrine facies is selected to obtain intensive systematic core samples. Core observation, thin section identification, X-ray fluorescence element analysis, X-diffraction analysis, scanning electron microscope, electron probe, rock pyrolysis, and other techniques are performed to systematically analyze the morphology, structure, thickness, mineral compositions, and organic matter content of the shale lamina in the Chang 73 submember. Five types of lamina are identified: silty felsic lamina (SF), tuffaceous lamina (TF), organic-rich clay lamina (ORC), organic-bearing clay lamina (OBC), and homogeneous clay lamina (HC), which are further subdivided into eight subtypes. The lamina types change greatly vertically in the Chang 73 submember, in which the lower part is mainly silty felsic lamina, organic-rich clay, and tuffaceous lamina, the middle part is mainly organic rich and organic clay lamina and organic-bearing clay lamina, and the upper part is mainly homogeneous clay lamina and a small amount of silty felsic organic-bearing clay lamina and organic-bearing clay lamina. Different laminae show various organic matter types, organic matter content (TOC), and organic matter occurrence states which can be divided into four occurrence types. The TOC in organic-rich clay lamina and part of homogeneous clay lamina is high, while that of silty felsic lamina is lower. The relationship between shale lamina and organic matter enrichment is established according to the correlation analysis of laminar characteristics, mineral content, and organic matter content. Among them, the organic-rich lamina is richest of TOC and is a favorable “sweet point” for shale oil exploration.

Coal and shale distributions on half-graben slopes: A case study of the Eocene Pinghu Formation in Xihu Sag, East China Sea

Steep and gentle slopes in a half-grabben basin often form oil source rocks of coal and shale. However, which source rock is dominant and what the relation is with the slope type and sedimentary facies are not clear. The Pinghu Formation in Xihu Sag is a half-graben basin with coal seam as the main source rock. Five condensate reservoirs have been found in its west slope, with several wells and 3D seismic data, which makes it possible to study the relationship between slope types and source rocks. We have used logging data, lithologic identification statistics, and seismic inversion to reconstruct the sedimentary facies and paleoslopes in the western Xihu Sag and have analyzed the variations in the proportions of coal and shale in the study area and their relationships with the facies, slope types, and subsag. The results indicate that the upper slope contained a higher proportion of coal than the lower slope. In contrast, the lower slope contained more shale than the upper slope. Coal is dominant in the delta plain and front facies, whereas shales are dominant in the prodelta facies. Although the proportions of coal and shale vary among the southern hinged margin, the central escarpment margin, and the northern hinged margin, the thicknesses of the coal and shale increases northward, independent of the rift margin type. These variations may be related to the filling of the delta from north to south during the deposition of the Eocene Pinghu Formation. These results also suggest that there were no substantial differences in the depositional slopes and water depths of the hinged and escarpment margins. The abundance of shales in the lower slope and at the center of the depression suggest that, in addition to coal, shales should have contributed to petroleum generation in Xihu Sag.

НОВЫЕ НАХОДКИ БИОДЕГРАДИРОВАННЫХ НАФТИДОВ В ПОРОДАХ ХАТЫСПЫТСКОЙ СВИТЫ ВЕНДА ОЛЕНЕКСКОГО ПОДНЯТИЯ

The geochemistry of organic matter (OM) and rocks from new sections of the Vendian Khatyspyt Formation on the Olenek uplift has been studied. The analysis of bitumens revealed signs of deep biodegradation of saturated hydrocarbons (HCs), demethylated terpanes in six samples. The present work is aimed at identifying the composition features of the OM components from rocks, containing biodegraded bitumens and assessing the Khatyspyt Formation rocks as potentially source ones. It was found that the rocks are enriched with OM, which accumulated under reducing conditions with possible sulphurous contamination of near–bottom waters, the water column was stratified. Its maturity on the Olenek Uplift corresponds to the initial stages of mesocatagenesis (the early oil window), it could generate naphthides. Comparative molecular analysis of saturated HCs showed that the source of biodegraded bitumens was represented by the dispersed OM of the Khatyspyt Formation. The peculiarities of HCs distribution indicate several stages of primary migration of bitumens. It is assumed that not only potentially oil source rocks can be distributed in the Khatyspyt Formation, but also rocks that are re-enriched with naphthides.

Comprehensive evaluation of Neoproterozoic source rocks formation

Based on comprehensive analysis of geological, geochemical, and paleotectonic settings, the conditions for the formation of Neoproterozoic oil and gas source rocks of the Earth are analyzed. A brief review of oil and gas fields in Eastern Siberia, China, the Middle East, Africa, and Australia is given, with Riphean and Vendian terrigenous and carbonate source rock. An overview of the oil and gas bearing basins of the world and a stratigraphic reference of the Neoproterozoic strata discovered within them, containing proven and suspected oil and gas source rocks, are given. The formation of Neoproterozoic oil and gas source rocks is analyzed in a complex way: simultaneously from the point of view of paleotectonics, paleogeographic and paleoclimatic conditions, paleobiological diversity and geochemical conditions. As part of paleotectonic analysis, the results of plate tectonic reconstructions for the Neoproterozoic stage are presented in accordance with one of the most currently relevant geodynamic models. Paleogeographic events and paleoclimatic conditions are described in the context of the specifics of the formation settings of carbonate-terrigenous oil and gas source rocks. In particular, the reasons for the accumulation of sediments enriched with organic carbon in the interglacial epochs of the Neoproterozoic and possible mechanisms for maintaining conditions favorable for their accumulation are considered. The conditions for the accumulation of oil and gas source rocks are also linked to global paleobiological pre-Phanerozoic events, and the analysis of the geochemical data of rocks makes it possible to characterize and correlate Neoproterozoic oil and gas source rocks on a global scale. On the basis of such a comprehensive assessment, a conclusion was made about fundamentally similar geological conditions for the formation of Neoproterozoic oil and gas source rocks in oil and gas bearing basins.

Structural reconstructions effect on oil and gas formation of the Yenisei-Khatanga trough eastern part

The article presents the results of research on the influence of structural reconstructions on the hydrocarbon systems evaluation in the eastern part of the Yenisei-Khatanga trough. Based on seismic data interpretation and paleoprofiles construction, several stages of structural reconstructions in the geological evolution of the basin are established: at the Middle and Late Triassic boundary, Late Triassic and Jurassic boundary, in the Bathonian-Callovian time, Tithonian-Valanginian time, in the Barremian-Aptian time, in the Aptian-Albian time, in the Cenomanian time, and powerful reconstructions in the Cenozoic era. Based on interpretation of geochemical information of the well-core and outcrops, the characterization of the type of organic matter, the amount of initial organic carbon, the oil and gas source potential for the Late Triassic, Lower Jurassic, Middle Jurassic, Upper Jurassic, Lower Cretaceous oil and gas source rocks is given. The results of exploration of the geological structure of the region, the geochemical features of oil and gas source rocks became the basis for building a 2D basin model, which made it possible not only to identify generation kitchen, migration routes and accumulation zones of hydrocarbon fluids, but also to estimate the start time of generation and emigration of hydrocarbons, as well as the moments of interruption of these processes during periods of uplifting of the territory. Changes of the structural plan transformed the configuration of the basin, which led, on the one hand, to the formation of areas where rich in organic matter interlayers accumulated, and, on the other hand, to the interruption of hydrocarbon systems evaluation, reconfiguration and even destruction of deposits.

Identification of the features of the organic matter of oils and source rocks based on a comparison of the results of geochemical analysis with statistical analysis built upon machine learning methods: the case of one field of the West Siberian basin

The idea of this work is to compare the results of geochemical and statistical analyzes in the study of organic matter in extracts of oil and gas source rock. The object of the study were the samples of oil and gas source rocks of the Tutleim and Tyumen Formations, as well as oil samples of the Vikulov Formation and Jurassic and pre-Jurassic deposits in the western part of the West Siberian basin. Among the methods of statistical analysis, the principal component method and the random forest method were used. A heat map of correlations was used as visualization tools. The principal component method helped us to reveal a clear difference between the organic matter of the Tutleim and Tyumen source rocks. The random forest method and the heat map made it possible not only to identify the distinctive geochemical properties for this strata, but also reveals the geological factors of their distinction. Thus, the organic matter of Tyumen source rock turned out to be more mature and it has relatively larger contribution of terrestrial organic matter compared to the Tutleim one. The same set of methods is applied to oil-source rock correlation. The oils of the Vikulov Formation obviously originate from the Tutleim source rock. Oils of Jurassic and pre-Jurassic reservoirs have a predominant contribution of the Tutleim source rock and some similarity (up to 30 %) with the Tyumen one. Oils from the Vikulov Formations are less mature than oils from the Jurassic and pre-Jurassic rocks. This may indicate the continued migration of hydrocarbons to Jurassic and pre-Jurassic deposits and the cessation of migration in the past to the overlying Aptian–Albian Vikulov Formation. Geochemical analysis also revealed the geochemical properties responsible for the maturity of source rocks and the type of organic matter. It confirmed the conclusions made on the basis of the application of methods of statistical analysis.

About the weathering effect on sedimentary rocks organic matter

To get properties and characteristics of oil and gas source rocks and for other geological aims, geologists analyzes core samples from wells and outcrop samples. But we should probably somehow correct geochemical source rock properties data we get on outcrop samples, because organic matter could change significantly due to oxidizing and weathering. This problem is very important but poorly developed in modern publications, so it attracted our interest and led to this investigation. Published information on the organic matter weathering which change it’s content and quality in sedimentary rocks is collected and summarized in this article. The changes of the kerogen (isolated from the mineral matrix) elemental composition during its long-term storage are presented. We compared the results we get in laboratory and results of other authors who dealt with natural changes of organic matter in outcrops. An attempt to interpret the results obtained from the point of view of hypergene changes in OM was made. Uncertainties that require further study and development are indicated. This work is the first step to better understanding of weathering effect on organic matter content and properties – question of great importance for making adequate oil and gas prospects estimations. This study continues the work of our foregoers and Teachers – geochemists of the Petroleum Geology Department of Lomonosov Moscow State University: N.B. Vassoevich, Yu.I. Korchagina, O.A. Radchenko, V.A. Uspensky, I.E. Leifman, A.N. Guseva, O.K. Bazhenova, T.A. Kiryukhina.

Variations in molecular and isotopes composition of seepage gases in the north-western and south-eastern parts of Lake Baikal

The paper presents results of gas-geochemical studies of bottom sediments and petroleum potential assessment of Baikal Rift Basin. During the expeditions of the Class@Baikal project in 2014–2019, gases from the Lake Baikal bottom sediments were analyzed. The results showed a clear difference in chemical and isotopic composition of the seeping gases collected in the northwestern and southeastern parts of the lake. The seepage released from northwest part were relatively enriched by methane and had a low concentration of C2+ compounds. The seepage gases had relatively lighter carbon isotopes composition of CH4 (from -72,7 to -50,1 ‰ VPDB) and the high variability of δ13C in C2H6 (from -65 to -22 ‰ VPDB). The gases released from southeastern part of the lake had an increase in C2+ compounds and had relatively lighter carbon isotopes composition of methane (from –57,2 to –41,0 ‰ VPDB). The carbon isotopes composition of ethane varies from -32 to -25 ‰ VPDB. Asymmetric structure of the Baikal rift basin and various processes of gas migration within it might cause the variations. Diffusive process led to the lighter carbon isotopes composition of the seepage gases from the northwestern part of lake and the gas molecular composition enrichment by methane. Such molecular and isotopic fractionations caused by geochemical processes helps to understand the migration of gas from source rocks to the earth’s surface. Similar geochemical indicators of fractionation should be taken into consideration when assessing oil and gas source rocks and basin potential from gas geochemical studies data.

Marine refractory dissolved organic carbon and transgressive black shales

<p indent="0mm">The marine refractory dissolved organic carbon (RDOC) pool, derived from the microbial carbon pump (MCP), holds a tremendous amount of carbon, as much as that in today’s atmosphere; hence, an understanding of this pool is crucial for investigating carbon cycling and climate change at the global scale. The size of the RDOC pool dynamically evolves over time. In the geological past, particularly during the Neoproterozoic to Cambrian transition, the marine RDOC pool might have reached a hundred to a thousand times its present size. However, the patterns of the reduction in the RDOC pool through time and the means by which RDOC was transferred into the geological reservoir have been poorly known to science. Black shales, which are the source rocks of oil and gas reservoirs and are enriched in many rare metals, are economically important sedimentary rocks. Black shale is characterized by the enrichment of clay sediments and organic matter (total organic carbon (TOC) &gt;1%). At least a dozen depositional models have been proposed to interpret various types of black shales based on the depositional environments and three major controls on organic content, i.e., the production and supply of organic matter, the demand and consumption of oxygen, and the rate of sedimentation. Organo-clay interactions and potential organic sources of the bulk RDOC in ancient oceans have not been fully considered. Clay minerals, e.g., smectite and illite, are well known for their capability of adsorption and preservation of dissolved organic matter in significant quantities. Organic compounds adsorbed by clays are present dominantly within interlayer sites and thus are difficult to be decomposed or used by microbes. Accordingly, here, I propose a hypothetical mechanism of RDOC deposition and preservation, which also functions as an alternative model for the origin of transgressive black shales that always abruptly contact the underlying rock unit. The proposed mechanism is outlined as follows: During global-scale sea level rise driven by crustal subsidence or climate change, upwelling currents transport RDOC-rich water bodies from deep oceans to clay-rich shallow sea depositional environments, where clay sediments mix well with the RDOC; the mixture triggers the interplay between clay minerals and organic matter, and thus leads to large amounts of RDOC being absorbed by clay sediments; after deposition, the clay sediments are able to absorb organic matter from pore water; finally, the organic-rich transgressive clay sediments form black shales through diagenesis. Experiments indicate clays are capable of absorbing as much as 12% or more dissolved organic matter, far more than the minimal 1% TOC in black shales. Therefore, it is reasonable to assume that the RDOC is an important organic source in transgressive black shales. The new model provides a potential link between ancient marine RDOC and black shales; hence, it might offer a mechanism for transferring marine RDOC into the geological carbon reservoir and thereby present an additional path of marine carbon cycling. Unlike the previous model that invoked primary production as the major organic source, the present model emphasizes the contribution of RDOC to the organic matter of black shales. However, it does not refute the contributions of any other organic source or any other model for transgressive black shales. To test this hypothesis, future work may include enhanced experimental studies of the interplay between clay minerals and organic compounds under different settings of temperature, pressure, and redox state, establish a set of geological criteria to recognize RDOC from organic-rich rocks, e.g., black shales; and quantitatively model the evolution of RDOC over geological time. Each of these tests would provide critical information for understanding the global carbon cycles of the past, present, and future.

A comparative study of organic-rich shale from turbidite and lake facies in the Paleogene Qikou Sag (Bohai Bay Basin, East China): Organic matter accumulation, hydrocarbon potential and reservoir characterization

Organic-rich shale (ORS) was developed in various sedimentary facies in lacustrine basins, displaying different organic matter (OM) accumulation processes, hydrocarbon potential and reservoir characterizations. Taking the Paleogene Qikou Sag (Bohai Bay Basin, East China) as an example, the ORS from two typical sedimentary facies in lacustrine basins, i.e., turbidite and deep to semi-deep lake were comparatively studied, based on the integration of mineralogical, bulk geochemical, organic petrographic, isotopic and elemental geochemical, and shale reservoir analyses. Under the influence of turbidity currents, the Es 3 2 ORS was formed in the paleo-lake characterized by low paleoproductivity, suboxic-oxic and freshwater conditions, and high detrital influx. However, high terrigenous OM input led to moderate TOC contents (avg. 1.58 wt%) and low HI values (avg. 193 mg/g TOC) in the Es 3 2 ORS of turbidite facies. In contrast, the Es 1 z ORS of deep to semi-deep lake facies was deposited in the paleo-lake with high paleoproductivity, suboxic and brackish water conditions, and low detrital influx, which resulted in high TOC contents (avg. 2.77 wt%) and HI values (avg. 335 mg/g TOC). Combined with the analysis of hydrocarbon potential and reservoir characterizations, the Es 1 z ORS of deep to semi-deep lake facies could serves as main source rocks for crude oil, whereas a significant shale oil potential is likely to observe in the Es 3 2 ORS of turbidite facies in areas with favorable maturity and high brittleness. Our results are conductive to the formation mechanisms of ORS from various sedimentary facies in lacustrine basins, and provide scientific guidance for hydrocarbon exploration in similar areas. • Accumulation models of organic matter in different sedimentary facies were established. • Hydrocarbon potential of ORS from different sedimentary facies was comparatively studied. • Reservoir characterization of ORS was revealed by multiple methods. • The ORS from different sedimentary facies plays different roles during hydrocarbon exploration.