The article is devoted to the anniversaries of the outstanding scientists who laid the foundation for the oil and gas geology – I.O. Brod, N.B. Vassoevich and I.V. Vysotsky.

For more than 30 years N.B. Vassoevich had devoted to the development of the theoretical foundations of petroleum geology and geochemistry. In addition, Nikolay Bronislavovich was always interested in the original meaning of the words that he used as scientific terms. Under the term, he understood a lexical unit that serves to designate a scientific concept, performing the function of naming in relation to the object reflected in this concept. According to N.B. Vassoevich, the ambiguity of many geological “terms” is the cause of most heated scientific discussions. Therefore, the ordering of scientific terminology and nomenclature N.B. Vassoevich included among the most important scientific tasks.

The article is devoted to the 120th anniversary of Nikolay Bronislavovich Vassoevich (1902–1981) – a famous petroleum geologist, professor, corresponding member of the USSR Academy of Sciences. The article recalls his significant achievements in the field of fundamental geology. The first and main work in this field was his monograph on the methodology for studying the sedimentation cyclicity of flysch strata (1948), with the continuation of the topic in the next book, published in 1951. The scientific heritage of N.B. Vassoevich, who headed the Petroleum Geology Department of Lomonosov Moscow State University in 1963–1981, is preserved and developed in the modern educational and scientific activities of this Department. Teachers, staff and students with deep gratitude and respect honor the memory of N.B. Vassoevich, using his methodological recommendations on sedimentation cyclicity both in the training course of lithofacial analysis and applied in practical work in the study of oil and gas bearing strata of sedimentary rock basins. A huge role in the development of the terminology of this theory is associated with the development of the conceptual base of this geological direction. Professor N.B. Vassoevich had invested continuous work on the creation of systematic and logical classifications according to the composition, structure, genesis and hierarchy of geological sedimentary bodies that make up oil and gas bearing rock complexes.

The Principles of the fluid-dynamic concept of oil and gas formation, which expands the ideas of the previously proposed of the same name model in co-authorship, are presented. The base of the concept – simultaneity of processes, which, in the presence of a significant vertical flow of fluids and heat, cause the emergence of structures, a new reservoirs and new dynamic barriers, oil and gas formation and the formation of deposits. The formation of certain types of sedimentary basins and then the selective formation of their “traditional industrial” oil and gas content from predominantly fossilized living matter are predetermined by the development of deep, not only specific crustal, but also mantle processes. Based on the theory of open non-equilibrium systems, the concept assumes vertical tectonopetrological stratification and alternation of de-compaction and compaction zones in the lithosphere and upper mantle, when disclosed, “catastrophic” heat-mass transfer of fluids from decompacted zones and pulsation oil formation are carried out not from the entire source organic matter, but only from the oil “semi-finished product”, and not from the basin as a whole, but in its individual parts.

The question of the correct terminology is highly relevant, since researchers should understand one another in communication with specialists in different branches of geology. An overview of the terms already existing in the English-speaking world for describing oil-prone macerals, such as alginite, bituminite, bitumen, solid bitumen, pyrobitumen, oil, was presented, and it is more convenient to combine all zooclasts into bioclasts, since it is not always possible to determine whether the remains belong to the animal or plant world. Particular difficulties emerged with the term “bitumen”, which in Russian has two meanings. Increasingly, the films between mineral grains can be named both bitumen and oil. It was also suggested to divide bituminite in pre-mature bituminite, mature bituminite and post-mature bituminite in order to emphasize the features of those transformations that occurred with the initial organic matter during thermal maturity. Due to the fact that in the process of thermal maturity, the reactive part of kerogen = bituminite will transform into a liquid and gas, its solid part (“residual organic matter”) was suggested to be called solid bitumen or pyrobitumen.

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.

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.

At present time several dozen hydrocarbon fields are known in the Vendian-Cambrian complex of the Lena-Tunguska basin, which clearly does not exhaust its potential. The significant stratigraphic interval of the complex, its thickness (up to 3000 m), favorable properties laid down in sedimentogenesis, namely the presence of source, reservoir and seal deposits, allow us to hope for the discovery of new oil and gas deposits. Sedimentological studies of the Vendian-Cambrian complex, carried out using a network of key lithological sections and outcrops, made it possible to create a series of schematic maps of sedimentation environments on a scale of 1:5000000 for six time intervals (Nepa, Tira, Danilovo, Tommotian-Early Atdabanian, Botomian-Amgaian and Late Cambrian). The evolution of sedimentation of the Vendian-Cambrian complex is considered, as well as an assessment of its oil and gas properties, which are primarily associated with various sedimentation environments.

The Lower Vendian oil and gas bearing play is one of the main ones in the Siberian platform and dominant within large tectonic elements (Nepa-Botuoba anteclise, Sayan-Yenisei syneclise, etc.). The oil and gas content of the complex is determined both by the conditions of its formation and by post-sedimentation processes, which are largely associated with the stages of formation and reformation of hydrocarbon pool. All these features of Vanavara reservoir were explored in a detailed lithofacies analysis of the core material of the Novo-Yudokon field and adjacent territories.

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, TithonianValanginian 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.

Two-dimensional basin modeling was carried out along regional profiles (sublatitudinal and submeridional). When modeling, the software package of Lomonosov Moscow State University was used. The models take into account the features of geological structure of the Riphean deposits of the Kama-Belsky aulacogene northern part and the VendianPaleozoic complexes that overlay it. Recent data on the features of region geology (taking into account the assessment of thickness of the eroded Riphean-Vendian deposits), as well as on the features of organic matter of the ancient Precambrian deposits were used. As a result, boundaries of the oil and gas window and geotemperature gradient were revealed. Main type of deposits according to the results of 2D basin modeling is anticlinal (reservoir-arch) and stratigraphically shielded. Data obtained testify, firstly, to two stages of hydrocarbon generation by the Riphean-Vendian oil source strata (the first stage occurs at the end of the Early Riphean, the second – at the Vendian-end of the Late Carboniferous), and, secondly, to prevailing share of the Riphean-Vendian complex of source strata in the formation of oil and gas content of sedimentary cover within the marginal zones of the Kama-Belsky aulacogen northern-northwestern part of the Volga-Ural oil and gas basin. Generation of hydrocarbons by source strata of the Riphean-Vendian and Late Devonian-Early Carboniferous continues to this day, however, it has rather an «inertial character».

The paper describes the structure and depositional conditions of a domanicoid high-carbon formation (HCF) in the central part of the Volga-Ural oil and gas basin. The structure of the HCF depends on the structural relatedness and paleogeographic conditions of the Late Devonian period, where the time of maximum sea level standing within the basin led to deposition of high organic carbon content intervals. The structural-facies zonation of the HCF distribution area is associated with the zone of relatively deep-water depressions, the zone of slopes, highs and the shallow water shelf with numerous bioherm buildups. The boundaries of the zones were determined by the position of large structural elements of the Tatar and Bashkir arches and depressions of the Kama-Kinel system of troughs. These zones differ not only in the distribution of the thickness of HCF deposits, but also in the nature of the distribution of intervals of the section enriched in organic matter. The maximum number of interlayers enriched by organic matter of the siliceous-carbonate rocks is observed in the section of the Frasnian and Famennian deposits within the central part of the Kama-Kinel system of troughs. Numerous of oil shows from the HCF intervals indicate the potential for further study and spotting of promising areas for hard-torecover hydrocarbon reserves exploration.

Domanic deposits have already been studied in sufficient details. Various aspects of their study were described previosly in many works, but so far, these deposits have been considered mainly as source rocks. Domanic deposits are distributed in a wide stratigraphic range from the Middle Frasnian of the Late Devonian to the Tournaisian of the Early Carboniferous. In this paper, domanic formation is considered as an unconventional reservoir. Due to the complex and heterogeneous structure of rocks, their uneven saturation with organic matter and low porosity values, the methodology for assessing reservoir properties is at a low stage of production. An integrated study of the void space in such deposits, including macro- and microdescription of the core, analytical studies, makes it possible to predict zones with best quality of reservoirs and helped successfullу produce such deposits. In the section of domanic formation were identified the main lithotypes and characterized of each of them. Comparison of the types of void space identified in thin sections and reservoir properties made it possible to classify the main types of reservoirs and assess their quality.

The article is devoted to the variation of generation potential of the Lower-Middle Jurassic organic matter in the Karabash area (South-Western part of the West Siberian basin) depending on facies and sedimentary cyclisity. Based on geochemical and lithological core studies, specific geochemical features of organic matter established for main facies groups of Early-Middle Jurassic in the study area. The best generation potential inherent in deposits of swamps, swampy floodplains and tidal plains. These facies groups characterized by predominance of the continental organic matter and considered to gas source rocks. However, macerals composition, kinetic spectra and biomarker analysis show the presence also of marine organic matter. Some facies groups, such as flooded swamps and swampy floodplains has potential to generate hydrocarbons due to preservation of liptinites with high hydrogen index. Cyclic analysis with basics of sequence stratigraphy of the continental deposits allow tracing the correlation between generation potential and relative sea level changes.

The article considers facies analysis and the application of its results for the typification of rocks of the Tyumen Formation. The aim of the article is to create algorithms for the differentiated interpretation of geophysical studies of well log data of the Tyumen formation based on a detailed study of the core.
Based on core studies, as well as geological, geophysical data and field information on the Tyumen Formation of some deposits in Western Siberia, the main groups of facies were identified, reflecting the hydrodynamic activity of sedimentation conditions: group 1 – high-dynamic conditions, group 2 – transitional conditions, group 3 – low-dynamic conditions.
On the basis of this typification, petrophysical models of the deposits of the Tyumen Formation were created: petrophysical functions were built with differentiation by facies zones, boundary values of petrophysical parameters were obtained to identify reservoirs of different sedimentation conditions, algorithms for differentiated interpretation of well log data were proposed, also based on test results and field geophysical survey, differences in field characteristics for different sedimentation conditions were revealed, linear oil reserves were calculated using a new petrophysical model.
The development and implementation of an integrated approach to the interpretation of well log data, taking into account the conditions of sedimentation, make it possible to increase the reliability of determining the properties of the reservoirs of the Tyumen Formation, and the efficiency of calculating the oil reserves.

The paper considers geochemical data on the biomarker composition of oils from the fields of the TerekCaspian oil and gas basin. Samples of oils from the fields of the main oil and gas bearing regions of the Eastern Ciscaucasia – Terek-Sunzha zone, Prikumsky swell, Piedmont Dagestan and the Middle Caspian Sea were studied. To determine the “geochemical” age of oils, the ratios of regular steranes in saturated oil fractions were analyzed. It was found that the value of the biomarker parameter St28/St29, which determines the geological age of the original organic matter for oils, varies widely – 0.36–1.47. The most “ancient” age (Devonian-Carboniferous) was determined for the oils of the Prikumsky swell and the water area of the Middle Caspian; in the Terek-Sunzha zone and Piedmont Dagestan, an increase in the proportion of St28 sterane is recorded in oils, which indicates a younger generation age (up to the Paleogene). The data obtained can be used to clarify the history of the formation of hydrocarbon accumulations in this region.

Oligocene-Lower Miocene clinoforms of the Maikop formation are productive in the Eastern and Central Pre-Caucasus region. In spite of commercial discoveries and long exploration history, Maikop formation is poor characterized by borehole data in the deep basins such as Terek-Caspian trough. Furthermore, there are challenges of the detail stratigraphic subdivision in the deep basins, correlation, sedimentary conditions and criteria of reservoirs exploration.
Based on seismic and borehole data analysis, sequentstratigraphic framework, distribution area, progradation direction, seismic unconformities and thicknesses of the 17 Maikop sequences are established. Estimation of the clinoforms height allowed reconstructing paleobathymetry and paleogeography of the Pre-Caucasus region in the Oligocene – Early Miocene. Clinoforms M1-M7 prograded from the northeast, sea depth increased from 300 to 450 m. During clinoforms M8 sedimentation, new provenance area appeared on the west, sea depth increases up to 800 m.
Clinoforms M12-M16 prograded from the north, sea depth decreases from 480 to 270 m. To the end of the M17 sequence deposition, starved deep basin was totally compensated.
Three morphologic types of the clinoforms are identified. Type I represents by tangential clinoforms up to 75 m of height, that interpreted as subaqueous delta. Type II are the sigmoid shelf-edge delta clinoforms up to 800 m of height. Clinoforms of type III are low-angle wedges, confined to the slope and floor of the deep basin. Height of the wedges does not exceed 270 m. In the topset of the shelf-edge deltas, shallow-marine sandstones and structural traps predicted, while basin floor fans and stratigraphic traps expected in the bottomset. Subaqueous deltas are regarded to stratigraphic traps, while the wedges are predominantly mud-prone.

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 C₂ H₆ (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.

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.

Nowadays well logging curves are interpreted by geologists who preprocess the data and normalize the curves for this purpose. The preparation process can take a long time, especially when hundreds and thousands of wells are involved. This paper explores the applicability of Machine Learning methods to geology tasks, in particular the problem of lithology interpretation using well-logs, and also reveals the issue of the quality of such predictions in comparison with the interpretation of specialists. The authors of the article deployed three groups of Machine Learning algorithms: Random Forests, Gradient Boosting and Neural Networks, and also developed its own metric that takes into account the geological features of the study area and statistical proximity of lithotypes based on log curves values.
As a result, it was proved that Machine Learning algorithms are able to predict lithology from a standard set of well logs without calibration on reference layers, which significantly saves time spent on preliminary preparation of curves.