The article investigates key success factors and reasons for failures of the oil sectors in countries of North and South America: Argentina, Brazil, Venezuela, Guyana, Canada, Colombia, and Mexico. It gives a brief overview of resource potential and dynamics of hydrocarbon production in these countries. The authors analyze such parameters of the oil sector development as technological progress, sector structure, efficient institutions, government energy policy, including fiscal system, energy reforms, i.e. promotion of competition, partial privatization of national oil companies, attraction of international oil corporations, ensuring a stable regulatory climate, and reasonable localization policy. Conclusion is made that a sustainable development of the oil sector and oil production growth that meets the strategic goals of the government depends not only on resource potential, but also on energy policy, sensible and timely reforms, viable institutions and favorable investment climate.

The current state of late stage oil field development is characterized by increasing water cut, the need to extract and transport large volumes of produced water, which significantly reduces the profitability of operating such fields. In this context, water shutoff operations hold a unique position among measures aimed at optimizing oil production operating costs. The paper presents the results of testing and implementation of a comprehensive waterproofing technology using sedimentary gel-forming compounds at the TashlyKulskoye field (the Republic of Bashkortostan, Russian Federation). The work was carried out in difficult geological conditions of the C1ksl formation of the Tournaisian stage, represented by monolithic carbonate reservoirs. The measures carried out have shown high efficiency about 95%.

Reliable data on the relative permeability of low-permeability organic-rich shale reservoirs are essential for optimizing the development and operation of these fields by enhancing hydrodynamic models. Key challenges and limitations in studying complex reservoir systems include limited experimental data due to a shortage of core samples and the inapplicability of conventional laboratory methods for characterizing gas flow due to properties of these reservoirs (low porosity and permeability, high amount of organic matter including kerogen).

Investigating the effects of ultra-low interfacial tension, sorption, and diffusion on fluid flow under simulated reservoir conditions is crucial. Despite the importance of these factors, mechanisms of sorption and diffusion of hydrocarbon gases in shale rocks are often overlooked in experimental and numerical research on recovery strategies.

This review aims to provide a comprehensive understanding of gas adsorption and diffusion related mechanisms in tight shale rocks. Main findings include assessment of how various rock properties affect fluid behavior in nanoscale pores and identify critical areas for experimental analysis. By generalizing the review results, this work also highlights emerging research trends and addresses limitations in integrating adsorption and diffusion data for recovery, improving the accuracy of recoverable reserve estimates and reducing economic risks in unconventional reservoir development.

This paper describes a novel approach for automatic depth shifting geophysical well logs data and whole core images. The proposed approach combines the use of machine learning algorithms for automatic lithotype description via whole core images and an amplitude modal inversion algorithm, enabling the integration of stratigraphic information during the shifting process. The automatic shifting with whole core images is performed without using the natural gamma radiation curve of drill core or core routine data. As part of this study, the proposed workflow was validated on clastic and carbonate datasets (including non-clayey carbonates rocks) for neutron and density logs. The automatic shifting results have high accuracy, with precision equal to that of the smoothing filter (approximately 60 cm for neutron logs and 80 cm for density logs.), according to the analysis of the processed data and comparison with core routine data. The proposed technique significantly reduces the time required for processing well logging data compared to traditional approaches, minimizes errors related to human factors, and can serve as a foundation for further research in this area.

Recent advances in machine learning have enabled the automatic analysis of microtomography (µCT) images, facilitating more efficient rock property identification. This study aims to predict the experimentally measured open porosity of reservoir rocks using µCT images of standard core plugs. A dataset of 136 core plugs was collected, including 49 sandstone and 87 carbonate samples. Open porosity was experimentally determined using gas volumetry. The core plugs (30 ± 1 mm in height and diameter) were scanned using µCT with a resolution of 34.6–38.0 µm, producing 16-bit image stacks. The dataset consisted of 100,232 images (64,119 carbonate and 36,113 sandstone). To label the images, we introduced a supervised method called Segmentation of Unresolved Pores via Experimental Reference (SUPER), which segments dark voxels to match the experimentally measured open porosity, adapting to each sample’s characteristics. Three shifted window (Swin) transformer models were trained: a universal model and specialized models for sandstone and carbonate. The models used transfer learning with ImageNet weights, followed by fine-tuning. Testing confirmed that specialized models outperformed the universal model. This highlights that training an ensemble of models adapted to specific rock types leads to better performance than a single general model for porosity prediction. A key challenge arose with sandstones, especially fine-grained types, where small pores merged due to resolution limitations. Future work should improve image resolution and feed detailed images into the model. The method has potential for full-scale core scans and early porosity assessment in raw core plugs, including fragile reservoirs with oil or bitumens.

In the article, using the territory of the western part of the Baikal-Patom belt as an example, an author’s approach to the automatic extraction of lineaments reflecting various scale levels of the development of the fault network framework is proposed, based on the sequential lowering of the spatial resolution of the FABDEM digital elevation model. The results of a comprehensive spatial-geometric analysis of the extracted lineaments, marking fault structures of various ranks, are presented. Based on correlation analysis, groups of structures unambiguously corresponding to a definite scale level are identified. For the reconstruction of the parameters of the stress-strain state, the kinematics of the proposed fault structures, and the restoration of the sequence of tectogenesis stages, the paragenesis of structures identified at each stage of generalization of the digital elevation model was interpreted based on the shear model proposed by P.L. Hancock. As a result, in the history of the geological development of the territory, three sequential stages of tectogenesis have been established, characterized by: I) sub-latitudinal – east-northeastern, II) northeastern, and III) northwestern orientations of the axis of maximum compression. The first stage is manifested at all scale levels and corresponds to the processes of accretionarycollisional interaction of the margin of the Siberian craton with microcontinents and island-arc terranes. The second and third stages are manifested exclusively at the local level and correlate with the formation of sub-latitudinal strikeslips and thrusts in the northwestern direction. The obtained results, based on the calculation of the tendency-to-shear coefficient and visualization of the most hydraulically active segments of the fault structures, formed the basis for creating multiscale predictive-prospecting models of mineral resources of the territory, taking into account the identified stages of tectogenesis. It has been established that the first and second stages played the greatest role in the localization of metallic ore mineralization. In this case, the accuracy of the complex model amounted to 94%.

This study presents the first 87Sr/86Sr isotope data for the Middle–Upper Devonian strata of the central part of the Volga–Ural petroleum province, which are based on ramiform conodont elements. The stratigraphic position of most samples was verified using platform conodonts they contained. The 87Sr/86Sr values obtained are consistent with the global strontium curve, indicating a contiguous connection between this region and the world ocean throughout the Devonian. These results confirm general stratigraphic completeness of the regional succession despite numerous discontinuities and the complex intercalation of black shales, siliciclastics, and carbonates.

This paper presents the results of a study of rhizoid limestones of the Urzhumian age, Middle Permian, on the example of one of the typical layers using field and laboratory methods to clarify their depositional settings. Bulk geochemistry, isotope analysis of stable carbon and oxygen isotopes, optical microscopy, scanning electron microscopy (SEM), X-ray computed tomography (XCT) and electron paramagnetic resonance (EPR) were used.

The limestone under study has a two-part structure: the main (lower) part is penetrated by a dense network of root canals (rhizoid limestone), and the upper part is composed of thin-laminated limestone (laminated limestone) with desiccation cracks filled with dark gray massive limestone. All limestone types contain lacustrine fauna of ostracods, bivalves and fishes. Rhizoid limestone has a micrite bioturbated structure, overlapping laminated limestone is characterized by microbially induced thin-laminated micrite-ostracod structure. Massive limestone has a micrite-peloid structure and hosts rhizoid limestone intraclasts.

Massive limestone filling desiccation cracks clearly differs from the host limestones in its “lighter” isotopic composition, the presence of microbial films with the development of coccoid and filamentous bacteriomorphs. The EPR spectra of massive limestone are characterized by the presence of signals from sulfate radicals and organic radicals of non-carbonized organic matter of plants.

Using XCT, the structure of root canals in rhizoid limestone was revealed, from which the distance between plants was estimated to be 10-12 cm. The morphology of the root canals allows them to be attributed to the ichnotaxa Radicites sp., and Radicites erraticus.

The studied rhizoid limestone is interpreted as a lacustrine carbonate sediment processed by plant roots during the shallowing of the lake. The laminated limestone is interpreted as bacterial mat formed in palustrine (littoral) environments. The massive limestone is a microbial structure of mud mounds type formed in littoral environments.

The recurrence of rhizoid limestone horizons in the Urzhumian sections reflects the cyclicity associated with short-term climate fluctuations, where rhizoid limestones are confined to conditionally transgressive phases of lake basin development. The lithostratigraphic potential of rhizoid limestones requires further study.

The purpose of this publication is to present the new geological and geochemical data on Potential source rocks of the Osinsky horizon of the Lena-Tunguska province. The Osinsky horizon of the Lower Cambrian within the Siberian craton has a complex facies structure and is represented by three main types of sections: shallow (arched), reef and depression. When drilling a new exploration and evaluation well at the Salair area (the southern part of the Kamov arch), from the depression-type section of the Osinsky horizon, continuous core sampling was performed, and for the first time for the Baykit High Province, detailed characteristics of potential source rocks were obtained. In the exposed section, the Osinsky horizon has a reduced thickness (12.5 m), and three members are identified in its composition. Weakly porous microbial dolomites with signs of oil saturation were identified in the middle member. The upper member is composed of dark gray and almost black limestones with characteristic signs of condensed anoxic sedimentation (micrite structure, micro-layered texture, absence of remains of benthic organisms, abundance of pyrite framboids, etc.). Numerous spherical remains of calcareous microplankton are found in it. Geochemical methods proved the rocks of the Osinsky horizon depression section are mainly oil-generating. According to the results of geochemical studies, it has been established that the Osinsky petroleum system in the research area is isolated from the underlying Vendian and Riphean deposits. The presented results are highly relevant, as they provide new information about poorly studied depression-type deposits of the Osinsky horizon of the Baykit High Province.

The paper discusses the peculiarities of group, molecular and elemental compositions of bitumens and oils of Usolskaya and Teter Formations of three fields of the central part of Nepsko-Botuobinskaya oil and gas bearing area. Oil (light and heavy) and bitumens (asphaltites and kerites) were studied. In addition to the standard study of free chloroform bitumoids “A”, bound chloroform bitumoids “C”, as well as products of ‘soft’ thermolysis of oil asphaltenes were isolated and analysed at the molecular level. Total ion current chromatograms of saturated fractions of naphthides of all studied samples (except for thermolysate of oil asphaltenes) are characterised by a clear predominance of n-alkane peaks, iso-alkanes, including isoprenoid ones – in subordinate amounts. In all samples of the studied naphthides a number of alkane and terpane facial-genetic molecular parameters indicate the unity of the type of initial bioproducers and reductive conditions of early diagenesis of source rocks. However, in the composition of some samples the increased content of cholestanes and rearranged steranes was registered which are not typical for ancient naphthides of the studied area. Specific HCs – 25-norhopanes C27-C32(C34), adamantanes C10-C14, dialkyl-substituted alkanes (presumably odd C21-C31) and normal α-olefins C14-C29 (in the thermolysate of oil asphaltenes) – were detected in the composition of the studied samples. The data on molecular parameters were processed by the principal component method, which showed differentiation of naphthides in terms of their confinement to the fields, as well as their type, presumably caused by a more intensive impact of thermal and migration factors in the Yuzhno-Danilovskoye and Danilovskoye fields. In general, according to the set of studies performed, it is assumed that the formation of the modern composition of the studied naphthides is also due to recharge of the deposits with new portions of hydrocarbon gases or methane oils. Additional studies of probable source rocks are planned to identify sources of naphthides generation in the studied area.

The aim of the investigation is to study the molecular composition of hydrocarbon compounds (HC) in the pore space of the Bazhenov horizon rocks in the northern part of Western Siberia. The oil and gas source rock samples with mixed and continental organic matter from two wells G5 and G6 were investigated. The biomarker analysis of the bitumen from open, blocked, and closed pores showed significant differences in the composition of HC, which allowed to divide them into two groups. The presence of migrated HC in the open pores of the studied samples was determined by the differences in the biomarker parameter values characterizing the conditions of organic matter sedimentary conditions. The composition of migrated bitumen expresses the oxidative conditions of the parent predominantly continental organic matter sedimentation. Bitumen in the closed pores, on the contrary, was formed from predominantly marine OM in the reducing conditions. The maturity parameters of bitumen confirmed that the migrated HC have a different source. The values of Ts/(Ts+Tm), Ts/C30, 4MDBT/1MDBT, TAI/(I+II) for migrated bitumen from G5 and G6 wells characterize the stages of early-middle oil window respectively, closed pore HC – the stage of immature kerogen to early oil window.

The sedimentary cover of the Russian Eastern Arctic, which includes the Laptev, East Siberian and partly Chukchi Seas, is considered one of the most prolific oil and gas provinces. However its petroleum potential is difficult to assess due to the lack of wells that can provide data on the presence and quality of the source rocks within the area. To address this issue, the paleogeographic conditions for the development of the main sedimentary complexes have been restored. Investigations based on the paleogeographic reconstruction and available geochemical data from surrounding areas indicate a high probability of source rock presence in the Upper Cretaceous, Paleocene-Eocene, and Oligocene-Early Miocene units of the sedimentary cover. These speculative source rocks have been studied through numerical modeling, to assess their maturity, transformation ratio and generation potential. This results in delineating probable hydrocarbon kitchens within the Eastern Arctic shelf. The findings obtained provide a conceptual basis for further evaluation of oil and gas prospects, zoning of the studied area, and effective planning of geological exploration activities.

Comprehensive lithological and geochemical studies were conducted on the core samples from three wells located in the southern periphery of the West Siberian Petroleum Basin (northern part of the Omsk region). These studies enabled the identification and detailed characterization of the main source rocks in the area, as well as the assessment of potential hydrocarbon generation volumes within the study area. The organic-rich siliceous mudstones of the Bazhenov

Formation, along with coals and carbonaceous shales of the Vasyugan and Tyumen Formations, were identified as the main source rocks. A detailed analysis of the well sections revealed that the generation potential of the Bazhenov Formation is associated with the Type II/IIS kerogen, which is characterized by early generation and a higher initial hydrogen index. The coals and carbonaceous shales of the Vasyugan and Tyumen Formations were determined to possess oil-generating potential due to the anomalously high content of liptinite macerals in the organic matter (OM) composition. The studies of the molecular and isotopic compositions of rock extracts from both source rock and reservoir rock intervals, as well as the gas sample from the field, confirm that the fluids across the area are derived from marine OM of the Bazhenov Formation and the carbonaceous matter of the Vasyugan and Tyumen Formations, as well as their mixtures. The obtained results demonstrate the presence of an early generation petroleum kitchen in the area studied. These findings contribute to a new understanding of the hydrocarbon prospectivity of the region. The study also highlights the necessity for 3D basin modeling to reassess the hydrocarbon resources and their localization within the southern periphery of the West Siberian Petroleum Basin.

Natural gas separation is an important process in wells equipped with electric submersible pumps (ESP) that affects the efficiency of the «wellbore-pump-tubing» system. Nowadays, the amount of knowledge about this process requires critical analysis and further improvement. The paper presents the results of studying the unsteady features of the process of separation of gas bubbles into the annular space in the near-intake domain of the well model with conditionally radial inlet. The results of the experimental bench tests, as well as the results of numerical simulation in dynamic multiphase flow simulator are analyzed. The experiments were carried out on a test rig with the inner diameter of the casing model 80 mm and the outer diameter of the intake module 64 mm, taking into account the possibility of measuring liquid and gas flow rates, as well as high-speed video recording of the processes occurring in the near-intake domain of the well model. Unsteady features of gas-liquid mixtures flow with the help of video frames in the near-intake domain for model mixtures “Water-Air” and “Water-Surfactant-Air” are shown. It is revealed that at small time intervals (<1 s) the regimes with slug-churn flow patterns are characterized by significant nonstationarity. The results of numerical simulation indicate that such unsteady behavior can lead to oscillatory operation of the well and ESP.

On the basis of critical analysis of the obtained research results the following promising directions are formulated: a study of theoretical basis of separation in the near-intake domain of a well; field and bench experiments; a numerical modeling of natural gas separation into the annular space of a well equipped with ESP.

Hydrodynamic modeling is an important stage in the design of rational development of oil fields. However, the process of model creation is accompanied by a large number of difficulties associated with the uncertainty of reservoir properties. This problem is especially relevant when modeling complex carbonate reservoirs. One of the key parameters required to create a hydrodynamic model are the dependences of relative phase permeabilities. The standard approach is to create single dependences of relative phase permeabilities for the whole reservoir. However, at such an approach the peculiarities of filtration in separate zones of the formation are minimized. Within the framework of this study we have created a hydrodynamic model of the field characterized by a complexly constructed carbonate reservoir, taking into account the facies zonality in determining the dependences of relative phase permeabilities. In the course of the work the laboratory studies were linked to different facies zones of the deposit. For each facies zone, approximation of relative phase permeability dependences was carried out using LET model. The distribution of selected facies in the hydrodynamic model by specifying different regions in a three-dimensional grid was carried out, and the loading of dependences of relative phase permeabilities by facies zones was also carried out. According to the modeling results, it was found that the use of separate dependencies of relative phase permeabilities for each facies zone increases the convergence of technological indicators of development with the historical trend compared to the standard approach. The study also included the design of geological and technological measures on the modified model taking into account facies zonality. The designed measures allowed for 10 years of forecast calculations to increase oil production by 5551.5 c.u. in comparison with the basic calculation, with practically unchanged watercut – 1.2%.

Fractured reservoirs are widespread and contain a significant share of hydrocarbon reserves. At the same time, the fracturing of rocks has a significant impact on the processes of oil field development. In particular, the use of flooding of fractured reservoirs can lead to rapid water breakthroughs to production wells. In this regard, it is important to study the characteristic distance between wells (well grid density) on the efficiency of reserve development in a fractured reservoir. The paper considers two-dimensional two-phase fluid flow of incompressible fluids in a fractured-porous reservoir. The study was carried out using the example of three variants of fracture systems with the same density, characterized by different degrees of connectivity. These fracture systems were obtained by random generation, with each fracture having a random position and orientation. The distribution of fracture length follows a power law. Simulation of fluid flow in a fractured-porous medium was carried out using a discrete fracture model. The influence of the characteristic distance between wells on the efficiency of reserve development was studied.

The study of equivalent permeability and oil recovery factor on the characteristic distance between wells showed that in a fractured reservoir, the placement of production and injection wells at small distances from each other, depending on the structure of the fracture system, can be either ineffective or associated with an increased risk.

A multi-parameter quantitative analysis of horizontal well productivity with multistage hydraulic fracturing under steady-state flow conditions was performed, based on a high-precision numerical solution of the 3D problem on a detailed finite-volume grid. The conditions justifying the application of multistage fracturing were identified along with the interrelationship of the main system parameters to achieve a target well productivity level. An analytical expression for an approximate criterion was proposed for the case when the inflow to the wellbore is negligible compared to that to the hydraulic fractures. The accuracy and limits of applicability of the most substantiated simplified analytical models for productivity calculation were evaluated.

The paper is devoted to the analysis of the influence of the shear rate on the results of hydrodynamic modeling in reservoirs when planning and optimizing polymer flooding technologies in oil production problems. Three-dimensional hydrodynamic modeling is performed taking into account that the viscosity of the displacing agent in the reservoir is calculated according to a tabularly specified dependence on the polymer concentration and shear rate. The paper presents the results of computational experiments for polymer flooding for a three-dimensional reservoir model with and without taking into account the shear rate for two types of oil and polymers. Evaluations of the polymer flooding efficiency are given. It is shown that the bottomhole pressure significantly depends on the shear rate. Therefore, failure to take into account the shear rate during planning may lead to incorrect conclusions about possible daily volumes and concentrations of polymer injection, incorrect predictions of bottomhole pressures, and also lead to significant distortions in the assessment of the effectiveness of polymer flooding as a whole.

Asphaltene flocculation and precipitation are the cause of a number of complications in oil production, including a decrease in the filtration-capacitive properties of the reservoir and bottomhole zone, the formation of highly viscous emulsions, and the formation of high-molecular organic and complex deposits. When designing physicochemical technologies for oil production, it is necessary to take into account the phase behavior of the oil dispersed system, including predicting the effect of process parameters and reagents on the stability of asphaltenes in oil. In the process of long-term development of a deposit, the heterogeneity of the reservoir system increases and, accordingly, obtaining experimental data on the stability of asphaltenes in oil is an urgent task for preventing technological risks at the stage of designing technologies for long-term developed deposits. Experimental studies on the analysis of asphaltene stability were carried out using oil samples taken from 23 wells of 3 fields. All fields have been developed for a long time and are characterized by heterogeneity of deposits in area and section. The obtained data are summarized in the form of graphs and diagrams reflecting the heterogeneity of the response of the oil dispersed system to external influences. Interpretation of the obtained results revealed the dependence of the colloidal stability of oil on its structural-group composition. The research results can be used in the design of physical and chemical technologies, minimization of technological risks associated with asphaltene precipitation and selection of wells objects for implementation.

Currently, for enterprises engaged in mineral extraction in the Solikamsk Depression, the issue of disposing of industrial wastewater – including produced water associated with oil extraction and brines generated during the mining and processing of potash salts – is highly relevant. The most environmentally safe method of disposal is considered to be deep-well injection into deep aquifers. The article analyzes the legal aspects of organizing and operating deep-well injection sites, including the use of existing licensed areas and the procedure for obtaining new licenses for injecting industrial wastewater into deep aquifers. Methodological approaches to underground wastewater injection, as well as criteria for selecting suitable injection sites, are outlined. An analysis of the geological structure of sedimentary strata in the northeastern part of the Volga-Ural oil and gas province is conducted, assessing their spatial distribution, filtration-capacity properties, and the compatibility of native groundwater with the injected wastewater. It has been established that the Tournaisian-Famennian carbonate complex is the most promising for industrial wastewater disposal. Applying an integrated approach to evaluating geological and technological factors will help develop effective solutions to reduce the environmental impact on natural systems.

This paper presents an assessment of the radiological hazard associated with natural waters in the eastern part of Novosibirsk Oblast. The study area is characterized by fresh and ultra-fresh groundwater with total dissolved solids ranging from 127 to 1,848 mg/dm³, predominantly of HCO₃ Mg-Ca, HCO₃ Na-Mg-Ca and SO₄HCO₃ Na-Mg-Ca composition. The geochemical conditions vary from reducing to oxidizing (Eh from –332 to +313 mV), with pH values between 6.1 and 9.5 and dissolved oxygen concentrations ranging from 0.51 to 16.59 mg/dm³.

The primary contributors to natural radioactivity in these waters are ⁴⁰K and members of the ²³⁸U decay series, including ²³⁴U, ²²⁶Ra, ²²²Rn, and other decay products. Measured activities were as follows: 40K – 0 to 85.5 Bq/dm³; 238U – 0 to 4.3 Bq/dm³; ²²⁶Ra – 0 to 25.2 Bq/dm³; and ²²²Rn – 1 to 1,161 Bq/dm³. Activity levels of thorium-232 generally clarke values, except in waters associated with the western and northwestern parts of the Novosibirsk granitoid massif (Kolyvan, Skala and adjacent areas).

To evaluate the radiological risk, several parameters were calculated based on the activities of ⁴⁰K, ²²⁶Ra, and ²³²Th: radium equivalent activity (Raeq), absorbed gamma dose rate in air (Dγ), annual effective dose equivalent (AEDE), external and internal hazard indices (Hex and Hint), and excess lifetime cancer risk (ELCR). The results indicate that natural waters of the the eastern part of Novosibirsk Oblast generally exhibit low radiological parameter values – well within international safety standards – and are comparable to those reported for natural waters in Iraq, Namibia, Yemen, Spain, China, and other regions. Consequently, these waters can be classified as safe for domestic (non-potable) use.

However, their use for drinking water supply is significantly restricted due to elevated and high concentrations of ²²²Rn, observed both in areas underlain by granitic bedrock and in regions with sedimentary deposits.

The natural radioactivity of waters in the the eastern part of Novosibirsk Oblast and the overall radiological background of the environment are primarily controlled by local geological settings. Exceptions include lake waters near Shilovo village and near a brick-manufacturing plant in the Dzerzhinsky District of Novosibirsk, where elevated ⁴⁰K activity is likely attributable to agricultural application of potassium fertilizers and the use of potassium carbonate in brick production, respectively.