Background. The crucial part of carbon capture and storage (CCS) technology implementation is the selection process of geological bodies suitable for the safe and efficient storage of a required amount of CO2 for an unlimited period of time. According to the worldwide experience of CO₂ capture and storage projects mature field, extensive aquifers, aquifers of oil and gas fields and other objects are used for CO₂ injection and storage. The choice of either option is associated with a number of challenges and uncertainties, so all major CCS projects include a substantial quantity of research.

Survey licenses began to be issued in Russia in 2021 for the purpose of geological evaluation and estimation of the potential related to the storage of greenhouse gases, including CO₂. In the article, the geological prospects of CO₂ storage are considered in the Central Federal District of the Russian Federation, where a significant number of CO₂ emitters (especially metallurgy and power plants) with emissions rated at 5 million tons per year or more are located.

The purpose of this work is to assess the possibility and risks linked to CO₂ injection in the Moscow syneclise and adjacent areas.

Materials and methods. The criteria and recommendations given in ISO 27914 standard and experience gained in CCUS projects, both operating and under development worldwide, were used for the selection of geological bodies and the evaluation of efficiency and safety. Regional geological data from Central Federal District sheets and information on underground gas storage facilities in the region were used.

Results. Several prospective formations for CO₂ injection and storage were found compliant with the criteria and main risks for this area were determined based on the analysis of currently available geological data.

Conclusion. In study was made preliminary conclusions about the possibilities of carbon dioxide storage in Moscow Syneclise rocks, as well as to identify topics of further research to remove the most significant uncertainties in the use of CCS technology

Introduction. One of the key tasks for seismic interpretation is the prediction of the geological structure of the studied formations. In particular, a common task is to estimate the net thickness of reservoirs based on available well statistics. Such a task is standard in the framework of dynamic wave field analysis and is often solved by constructing a predictive model based on available geological and geophysical information, including values of net thickness in available wells.

Goal. The purpose of the work is to evaluate the effectiveness of machine learning methods in solving the problem of reservoir thickness prediction based on seismic data. Modern data analysis often uses this category of methods to build various predictive models. Seismic interpretation, in turn, is often associated with the use of relatively simple linear models. This makes it relevant to determine the gain from the use of complex prediction models.

Materials and methods. To carry out the study, a relatively well-studied area of one of the fields in Western Siberia was used. The territory under consideration is completely covered with 3D seismic data, there are 170 wells for constructing the model, in which the value of net thickness is determined.

To implement the study, both a standard linear regression and more complex machine learning algorithms are considered. Among the algorithms, multidimensional regression, random forest method, nearest neighbor method and neural network are considered. To assess the quality of prediction, the available sample of wells is divided into training and validation samples consisting of 80 and 90 wells, respectively. All calculations are implemented using open python programming language libraries.

Results. As a result, distributions of the expected accuracy of the forecast for each of the considered methods were obtained. The text of the article describes in detail the research algorithm, as well as the tests performed to select the parameters of each algorithm.

Conclusion. The results obtained allow us to conclude about the effectiveness of using machine-learning methods. All the approaches considered make it possible to obtain a more accurate prediction of the net thickness compared to the linear regression approach. The most significant increase in accuracy is observed with using a neural network and the improvement estimated as 23 %

Goal. The article demonstrates the approaches for integrating the results of point and interval testing into petrophysical model in order to expand the understanding of the reservoir and to predict parameter Kh from well logging data.

Methods. At the first stage of the work, specific methods were identified for considering the data of the complex of tests by hydrodynamic logging and wireline formation test installations in the reservoir model by petrophysics. Moreover, in the conditions of low-permeability deposits, special attention is paid to the issue of obtaining the so-called dry mobility measurements during the HDD-OPK and their inclusion in the reservoir model.

At the second stage, the authors consider the integration of flow testing data and the results of hydrodynamic logging and wireline formation test and formation evaluation from well logging. To carry out such a task, it is necessary to verify and classify the results of flow testing by reliability, which became possible due to the developed criteria for assessing the quality of flow testing in this work. qualitative results of flow testing make it possible to operate with the value of Kh as a calibration when calculating Kh by well logging. Thanks to high-quality measurements of fluid mobility by the wireline formation test in the Achimov deposits, the permeability is transformed from absolute to effective individually for the type of fluid: gas, oil, water. After that, Kh prediction itself is carried out on the basis of well logging data, controlling the value of Kh (well logging) with Kh (flow testing). The uncertainty of the well logging reservoir model is removed by cross-plotting Kh (well logging-flow testing) in such a way that the correct reservoir model with the correct NET pay by logging forms the maximum match between the predicted Kh and the calibration one from the flow testing at the points of the calibration wells. This is facilitated by the low level of permeability of the Achimov deposits, which has little effect on the Kh value, in contrast to NET pay.

Results. 1. Methods have been obtained for considering the data of the complex of tests by the hydrodynamic logging — wireline formation test installations in the petrophysics's reservoir model. 2. A tool was obtained for calculating the predicted Kh from well logging data, consistent with the actual Kh data from well testing. 3. Universal criteria have been identified for assessing the quality of well test results. 4. A non-standard way of confirming/ refuting the petrophysics's reservoir model using cross-plotting Kh (well logging, formation evaluation — flow testing, fact) is proposed.

Conclusion. In the work, it was possible to build a unified scheme of actions for the implementation of both the first stage of work on integrating the results of the hydrodynamic logging — wireline formation tests into t petrophysics’s reservoir model, and the second stage according to the Kh forecast based on the well logging, calibrated to the actual well test results. This representation allows not only to improve the accuracy of the petrophysical forecast, but also to expand the coverage of the involved data from related areas of petroleum engineering.

Background. Evaluation of filtration-capacitance properties of fractured carbonate section in most cases is associated with difficulties due to the high lithological heterogeneity of deposits, heterogeneity of properties both along the section and laterally, the complex structure of the void space of collectors, and most importantly, the presence of a system of fractures that causes fluid filtration in reservoirs of this type. For a more homologous modeling of filtration behavior and achieving the maximum production level, it is important to carry out a differentiated study of the filtration-capacitance properties of the carbonate reservoir

Aim. Within the framework of the work, the methodology of petrophysical typification of complex carbonate deposits of the Bashkir tier was developed. Now there is a wide variety of modern methods for the differentiated assessment of the filtration properties of carbonate reservoirs, including the use of the results of the interpretation of Hi-Tech methods and various statistical algorithms. The purpose of the work was to test the recommended methods by leading manufacturers of downhole equipment and software vendors to identify the most optimal and effective solutions.

Materials and methods. The Bashkir tier reservoirs were typified by integrated analysis of the results of HI-TECH methods, core studies, production data and well logging by involving the appropriate algorithmic base, as well as machine learning methods at the clustering stage

Results. Based on the results of combining the results of fracture assessment using various algorithms for the analysis of borehole materials, petrotypization of the studied carbonate section was performed and an electrofacies model was developed that allows the prediction of selected petrotypes for a specific well logging data complex using machine learning methods in automatic mode.

Conclusions. The identification of reservoir types by well log data is the first step to their differentiated study. Differentiated study is important because it allows you to more accurately determine the characteristics of the formation. Hydrodynamic studies, in which intervals with different types of void space simultaneously participate, lead to an ambiguous interpretation. In the proposed research program in new exploration wells, the typing of reservoirs according to the described methodology is an important element in the scheme of hydrodynamic and core studies. The presence of fractured reservoirs in the section has a significant impact on the drainage of the deposit and approaches to the development of the deposit, which makes it necessary to consider this feature in the hydrodynamic model to reproduce the characteristic effects of the presence of a system of fractures. The goal of differentiated research is to build a hydrodynamic model of a dual porosity and permeability.

Introduction. It is known that during crystallization, water expands, which leads to an increase in the pressure of downhole water samples when they are cooled below 0 °C. At the same time, in open sources there are no quantitative estimates of the conditions inside the receiving chambers when they are frozen.

Materials and methods. Measurements of pressure and temperature of a downhole water sample during its cooling were carried out using an internal pressure and temperature sensor built into the piston of the sample chamber.

Results. The dynamics of PT-characteristics of a deep sample during its freezing is described. The pressure increase was 120.5 MPa upon cooling from 10 to -15 °C.

Conclusion. For the first time in the public domain, a quantitative assessment of the increase in pressure of a downhole sample during its cooling is presented. Information on the requirements for temperature regimes of storage and transportation of samples is summarized, priority areas of R&D are proposed to reduce risks when working with downhole samplers.

Introduction. Long-term repair work with killing gas wells with saline solutions can significantly worsen the reservoir properties of productive formations due to water penetration into the reservoir rock. The Neocomian formations have a high potential for gas production and are developed using horizontal wells, the length of which is more than 1000 m. In this regard, when carrying out workovers of gas wells, an urgent task is to use methods of temporary isolation of the formations to maintain high production rates. Despite extensive experience in the use of retrievable packers for gas-blocking operations, the technologies for safely retrieving this type of equipment without the involvement of specialized equipment have not been developed.

Target. The use of a bridge packer plug for temporary isolation of the productive horizon and a viscoelastic composition for its safe extraction during long-term repair work on gas wells.

Materials and methods. To reduce the negative impact of killing fluids on the porosity and porosity characteristics of the formation during repair work, a technology for installing a bridge packer plug for temporary isolation of the formation is proposed. Due to the inaccessibility of the fields of the Far North, it is proposed to carry out work on extracting the packer plug without the involvement of specialized equipment by pumping a viscoelastic composition into the liner interval below the packer plug after its failure to isolate the formation for the duration of tripping operations.

Results. A solution was tested for temporary isolation of productive formations by using a retrievable packer device. The extraction of the packer device was carried out in a safe mode by using a viscoelastic composition with adjustable characteristics. After the repair work on the well, the design production indicators were achieved, and the reservoir properties of the reservoir were fully preserved.

Conclusion. The use of the technology of installing a recoverable packer with its subsequent extraction without the involvement of specialized equipment is a highly promising solution for maintaining the productivity of the Neocomian formations.

Background. Injection and production wells integrity play a key role in energy balance throughout reservoir development especially in mature fields as it becomes challenging to pressure support depleted target reservoirs. A large differential pressure between target and untargeted zones tends to cement integrity failure resulting thief injection and high water cut in oil production wells. This directly impacts water flooding efficiency, production efficiency and indirectly significantly increase carbon footprint during reservoir development of mature field.

Aim. To improve workover efficiency and carbon footprint decrease a way to enhance conventional diagnostics is presented in this work.

Materials and methods. A special approach of production logging called through-barrier diagnostics including passive spectral acoustics and temperature modelling for quantitative analysis of thief injection or production profile is described in this work.

Results. A number of through-barrier diagnostic cases revealing a true source of water in oil wells with high water cut and thief injection in water injectors are presented in the work as well as information on remedials for each case.

Conclusions. This work shows how through-barrier diagnostics helps operators to accurately allocate a reason of high water cut in oil production wells and thief injection geometry in injection wells unlike conventional diagnostics that can only detect water entering the wellbore. In presented cases, through-barrier diagnostics leads to a significant reduction in water volumes and CO₂ emissions, and increased field production.

Introduction. The article discusses multi-stage hydraulic fracturing (FRACKING) and its monitoring in real time with accompanying analysis of events in the well and determination of fracture development intervals. This approach makes it possible to carry out an operational assessment of the quality of current work without stopping the hydraulic fracturing process, namely: determining the leakiness of equipment, positioning the fracture development zone of hydraulic fracturing and a number of other parameters.

Goal. The purpose of this work is to demonstrate an approach that allows for the analysis of events during hydraulic fracturing in real time based on the developed proprietary software and hardware complex.

Materials and methods. As a basic approach, the technology was developed and the blocks of the proposed technology were structurally worked out, consisting of a pressure recording sensor, an electronic data acquisition device, software for digitizing data and packaging them on a server, software and algorithmic software for analyzing and interpreting recorded data.

Results. The authors show the experience of using the developed technology on the example of real measurements performed during hydraulic fracturing, the results obtained allow us to conclude about the efficiency of the technology and the convenience of using this approach in comparison with technologies requiring the descent of measuring devices to the bottom of the well. A comparative analysis with one of the applied reference technologies showed similar results, in the aisles of the current error of the described method, and this allows the technology to be used for mass monitoring of hydraulic fracturing operations.

Conclusion. The experience of using the developed technology shows the need for further accumulation of the amount of data, which makes it possible to improve the accuracy of interpretation based on the accumulated statistics. Carrying out several operations at each specific field and with a certain well design allows you to calibrate the developed algorithms and then put monitoring on stream using a minimum amount of additional information on the well.

Background. This paper presents a new technology for determining the inflow profile in the development of oil rims using chromate desorption systems.

Aim. quantification of fluid inflow in each well interval, diagnostics of water and gas breakthrough intervals.

Materials and methods. Chromate-desorption systems (CDS) are a polymer composite material into which unique chemical substances — analytes are packed at the manufacturing stage. CDS are installed on the elements of the lower completion of the investigated well. Upon contact with the target fluid, corresponding analytes begin to be released from the CDS, which are brought to the surface with a flow of liquid and/or gas to the sampling point. At the wellhead, sampling is carried out according to a pre-planned program, the analysis of the composition of the inflow is performed in the laboratory using chromatography methods. The technology makes it possible to determine the changing inflow profile and the dynamics of the well as a whole without conducting well logging.

Results and conclusion. During two years of research, 194 fluid samples were taken to determine the fluid inflow in each interval of the PT1 well. At the same time, 23 gas samples were taken to diagnose gas breakthrough intervals. Based on the analysis of gas samples, it was determined that gas comes from all five intervals. A quantitative assessment of the gas inflow was made, taking into account adjustments for the rate of release of analytes in each interval. A quantitative assessment of the oil inflow for each interval was made. Comparison of oil inflow profiles obtained using tracer and geophysical surveys showed comparable results.

Objective. Improving the profitability of exploitation of brownfields based on technical-economic values optimization takes on great importance at present time. The relevance of these works is connected not only with the technological and economic component, but also to a large extent social, since it is important to maintain and develop the production infrastructure near such fields, which are already located in developed and often densely populated areas of the country.

A promising direction for increasing profitability of exploitation of brownfields is further application, improvement and updating of existing methodological approaches and technologies of physicochemical and hydrodynamic EORs, aimed to stabilization of oil production, decrease in the rate of well production watering, recoverable reserves increment, decrease OPEX.

Materials and methods. The results of assessing the dynamics and degree of oil reserves recovery, calculations of the recoverable reserves increment, technological and economic effect from the implementation of various technologies of physicochemical and hydrodynamic EORs were used.

Results. The article shows the need to improve and update the existing methodological approaches to the application of physicochemical and hydrodynamic EORs technologies as one of the important areas for the development of the fuel and energy industry in the medium term. At the same time, scientific support for EOR projects stands out among the key areas, the purpose of which is a high-quality selection of well treatment area and technologies, evaluation of the effectiveness of technologies and determination of the optimal volumes of injection of chemical components, correct business planning and monthly distribution of the effect, achievement of the technological and economic potential of the main and additional programs physical-chemical and hydrodynamic EOR, decrease unit OPEX.

Conclusion. The individuality of the geologic and physical reservoir characteristics / separate reservoir areas and wells does not allow achieving consistently high results through the use of one universal EOR technology. High technological efficiency and duration of the effect, and, as a result, the profitability index is achieved by targeted treatment using individual compositions of chemicals, treatment designs and technologies for specific conditions of the reservoir / area, taking into account the existing problems, the current field development status and interaction with surrounding wells within a single oil-field exploitation system of a productive layer. Such an approach, based on the principles of treatment of reservoir on systems approach, is one of the ways of rational field development.

Background. The gas lift method of production is used on offshore projects. The advantage of this method is due to the ability to provide a high time between failures of downhole equipment, which is important for offshore fields, because well workover to replace a failed downhole equipment in offshore conditions requires to use of an expensive drilling rig. But despite the advantage of this method, gas lift does not allow to achieve such low bottomhole pressures that ESP provides and, as a result, realize the potential of wells (especially in highly watered wells). As a result, the introduction of ESPs can provide lower bottom hole pressures and significantly increase the level of field production. However, the re-equipment of wells from the gas lift production method to the ESP requires additional investments for carrying out workover program.

Materials and methods. A novel approach for rapid selection wells-candidate of re-equipment from gas lift operation to ESP has been developed in this article. The method is based on using the Net Present Value — model of wells operation on offshore field.

Results. The article presents dimensionless parameter sets, which used to construct universal diagrams for searching and ranking wells-candidate for ESP running. Approbation of the developed approach is shown on the example of solving problems of justifying geological and technical operations at the field of JV Vietsovpetro. It is shown that for fields with high residual reserves developed by offshore platform with the end of their service life, it is advisable to use ESP as a method of additional recovery of reserves, increase in recovery factor and economic efficiency of development.

Conclusion. The method presented in the article is applicable both to offshore and onshore fields, taking into account the adaptation of the economic model to the conditions of a particular project.

Background. The “Optimized Design” technology of well design is based on a set of measures aimed at reducing the cycle and cost of well construction. For the first time, this drilling method was tested at «Slavneft-Megionneftegaz» in July 2017 at a part of the right-bank group of fields.

Despite difficult geological conditions, the new approach to improving drilling efficiency is planned to be replicated at the Taylakovskoe and Zapadno-Ust-Balykskoe fields, where the bulk of well construction is currently underway. Aim. In order to optimize the existing design of horizontal wells at the Taylakovskoe and Zapadno-Ust-Balykskoe fields, an integrated approach was implemented, including the selection of the optimal horizontal well design and minimization of drilling risks by building a one-dimensional geomechanical model.

Materials and methods. Based on the results of the analysis of experience in the use of two-string assemblies, a comparative analysis of typical three-string and two-string assemblies was carried out, applicability criteria for these fields were identified, and economic and technological forecast parameters were evaluated.

When building a geomechanical model through additional research work: injectivity test “Leak-off Test”, cross­dipole acoustic logging, as well as special studies on the core, it was possible to determine the “safe” drilling window, hydraulic fracturing gradients, manifestations and losses, issue recommendations for mud densities and well design.

Results. Because of the work, the conditions for the safe replication of well drilling technology according to the “Optimized Design” for the Taylakovskoe and Zapadno-Ust-Balykskoe fields were determined; candidates were selected and calculated for testing of the work methodology.

Conclusions. An integrated approach to replicating well drilling technology based on an optimized design at the Taylakovskoe and Zapadno-Ust-Balykskoe fields will ensure the possibility of trouble-free and safe work and reduce the cost of well construction.

Purpose and content of the work. In recent years, the trend towards responsibility and environmental friendliness has increasingly captured the oil and gas industry. Modern enterprises focus on regulating and reducing harmful emissions. The combustion of associated petroleum gas (APG) is becoming one of the most important environmental problems of the Russian oil and gas sector, since the volume of APG combustion in our country is the largest in the world. Thus, the Volga Gas company decided to create a project in order to abandon the combustion of associated gas in favor of its subsequent use as an additional production product.

General approach, including the methods used. Due to the fact that about 17 billion rubles are burned annually at Russian enterprises. m³ of associated petroleum gas [4], since it is not the main product and specialization for oil companies, a technology for the utilization of flare equipment and the use of APG as an additional product of production was proposed on the basis of the existing enterprise. Initially, the project of the enterprise assumed the burning of part of the gas on flares, which led to environmental pollution and loss of product. The Volga Gas company assessed the profitability and feasibility of the technical implementation of a new project for the disposal of flares, which showed positive results. Information and 3D modeling have become important tools in the implementation of this project.

Results and main conclusions. As part of the project for the transition from flaring of associated petroleum gas to its processing, the design, selection and purchase of equipment was carried out, which led to the technical re-equipment of the existing enterprise. After the construction, implementation and launch of this technology, additional gas appeared in production, from which useful fractions in the form of liquefied petroleum gas (LPG) were subsequently isolated. Since the mineral extraction tax (MET) had already been paid, the resulting product was not subject to MET and excise taxes, which led to an increase in production profits. As a result of the exclusion of the waste of a valuable non-renewable resource due to flaring by Volga Gas, an additional production product was obtained, which was subsequently completely processed and sent to the market. Thus, the amount of CO₂ emissions into the atmosphere was reduced, and in addition to the profit from the initial gas production, the enterprise received.

Description of the novelty of the work. Since currently 25-30% of associated petroleum gas is burned at flare plants in Russia, this technology has become a technical breakthrough in the field of greening the production and processing of APG to produce liquefied petroleum gas. Also, a feature of the project carried out by the Volga Gas company was the speed of its implementation: thanks to technical re-equipment, the project was implemented within 6 months. As a result, the installation was successfully introduced into production, and emissions of harmful substances at the existing production decreased several times.

The aim of the present work is to substantiate and develop a methodology for automatic fire extinguishing installations full-scale fire testing.

Materials and methods. Analysis of the risks of accidents associated with a fire at small-scale LNG production and consumption sites allows us to describe the most likely scenarios for the initial stage of a fire. Based on this analysis a test rig has to be developed. It will simulate the initial stage of a fire at an object. On the testing rig, full­scale tests of automatic fire extinguishing installations are carried out and their fire extinguishing characteristics necessary for the designing of installations are determined.

Results. Full-scale fire tests were carried out to extinguish a natural gas leak with a gas-powder fire extinguishing installation. A new solution for automatic fire protection of small-scale LNG production and consumption facilities has been proposed.

Conclusion. Analysis of fires at facilities with LNG handling shows that the most possible scenario leading to a fire is the depressurization of one of the system elements with a relatively small outlet hole (from 2 to 10 mm) and an LNG flow rate of 0.3 to 1.5 l/sec. This jet combustion could be effectively suppressed at any point of the protected local volume by creating a fire extinguishing concentration of a gas-powder extinguishing agent. 

The article presents directions and tools for creating the concept of an autonomous asset, and gives examples of ongoing projects that correspond to the main focus of research at the current stage: the development of industry 4.0 infrastructure and complex engineering and solution typing.

Materials and methods. The analysis of the business needs of representatives of various types of assets was carried out. The interest in the development and creation of the concept of an autonomous asset has been revealed, but a differentiated approach to each specific asset is needed. Digital R&D projects are being implemented to remove uncertainties and increase the autonomy of objects within the framework of creating the concept of an autonomous asset.

Results. A matrix of the target level of autonomy was formed, taking into account the type of maturity of the asset and the availability of infrastructure, three development directions were identified for creating the concept of an autonomous asset, and tools for creating the concept of an autonomous asset were analyzed. As an example, the interim results of projects related to the development of industry 4.0 and complex engineering are given.

Conclusion. The presented results allow us to conclude that there are tools in the company and the need for an integrated and differentiated approach to create the concept of an autonomous asset.

Background. The field of knowledge of LNG decarbonization is modern and relevant. Since the first carbon-neutral LNG supply appeared in mid-2019, more than 30 supply transactions have been completed (mainly to Asia-Pacific countries). Gas is expected to be a key energy carrier in the coming decades in period of active energy transition. Reducing CO₂ emissions during LNG supply is an essential part of the sustainable environmental development for countries and companies. This causes the growing interest of companies and associations (GIIGNL, GECF) in the development of unified methodologies for calculating and accounting of emissions in whole the chain of production, transport and consumption of LNG.

Materials and methods. The article presents the overview of international experience and comparison of various approaches to account and minimize the carbon footprint of LNG. The methods of system analysis of scientific researches and industrial reports were used.

Results. The review study described in this article, for the first time in Russian, covers in detail the issues of reducing the carbon footprint for LNG. The average batch of 70,000 tons of LNG in production, transport and consumption generates emissions of about 240,000 tons of CO₂-equivalent. For LNG supply to be recognized as carbon neutral, CO₂ emissions from the full cycle of production, liquefaction/transport and consumption of natural gas must be included. It is emphasized that there are various options to reduce CO₂ emissions, which are divided into 3 categories: compensation with natural solutions, reducing emissions through energy efficiency, avoiding emissions through renewables and carbon capture and storage in geological reservoirs (CCS). The main share of emissions, 67-75%, comes from the end-use of LNG with combustion at power plants (Scope 3), while the processes of gas production, treatment / liquefaction, maritime transport and regasification (Scope 1, 2) account for about 25-33%. Companies currently offset their emissions with natural solutions (from companies' nature project portfolios or carbon credits purchased from voluntary markets). In the medium term, companies are aiming to improve energy efficiency and the introduction of renewable energy, in the long term — to capture and store in geological storages (CCS).

Conclusions. Finally, groundwork has been created for further researches and applied studies, which is especially relevant due to the growing interest of the government and industrial enterprises in reducing the carbon footprint.

Introduction. Various scouting tools are used for finding technological solutions. The selection of the most appropriate tools depends on the ultimate search goals and used sources of information.

Aim. To evaluate an efficiency and suggest the directions for the development of the main types of technology scouting tools.

Materials and methods. The article proposes an existing tools classification, detailed examples of each type application analysis, and numerical performance indicators.

Results. The combination of active searching tools has the highest conversion of adopted ideas into verifiable technologies. The tools for passive task publication and concomitant collecting proposals have a relatively low conversion rate.

Conclusion. Conclusions are made for the effectiveness of the tested tools and directions for the scouting development.

Purpose of the article. Review the technical and economic parameters of CCUS technologies and identify the most attractive market niches for them.

Materials and methods. An analysis of the CCUS value chain was carried out from the standpoint of the level of TRL. Further, in the most developed segments, the cost levels for each segment of the technological chain were analysed.

Results. An analysis of TRL of CCUS technologies showed that, as of 2021, most of these technologies are at the demonstration stage or at the stage of a large prototype.

Cost analyses across the entire CCUS value chain show wide variability among the literature reviewed and identify the CO₂ capture stage as the most expensive stage in the CCUS value chain. It demonstrates an impressive range of CO₂ costs, currently ranging from $20 to $450/tCO₂. Note the lack of data on specific capture processes and technologies.

Conclusion. In 2020, the average CO₂ price was less than $10/tCO₂, however, in a number of countries, such as Switzerland, Finland, Sweden, Norway, Canada, France and Korea, the CO₂ price already today allows some CCUS projects to reach profitability threshold. The analysis of technologies carried out by the authors at the TRL 9-11 also shows that there are already certain industries in which CCUS technologies can help in decarbonisation, and for some of these industries (for example, natural gas processing and fertilizer production), the costs of throughout the value chain start at $20-25 per ton.

The most promising areas at the moment are the application of CCUS in the chemical industry, ferrous metallurgy, natural gas production and coal-fired power plants. Note that ferrous metallurgy and the chemical industry are the sectors where it is most difficult to apply any alternative methods of deep decarbonisation.

Background. To date, integrated modeling (IM) tools of various configurations are used on most of the Company's Assets. With the help of IM, it seems possible to solve specific production tasks of various kinds, the prevailing list of tasks at the project implementation stage concerns identifying bottlenecks, optimizing technological regimes to maximize production, calculating the system for collecting and transporting well products, as well as determining the optimal strategy of the Asset. The implementation, development and use of IM tools in oil and gas companies can largely improve the quality and value of engineering calculations.

All integrated models used have many variables, which in practice makes it much more difficult to find the optimal objective functions, therefore, as a rule, optimizers built into the IM tool package or separately developed external add-ons are used to solve the tasks. With the advent of new equipment and optimization options, it is necessary to expand the functionality of both the IM tools themselves and various types of optimizers. This work is devoted to the development of an optimizer based on IM using primary automation tools (scripts), which contributes to solving the complex problem of debottlenecking in the well production collection system by using small-sized block separation-pumping units (SBSPU) and gas discharge, including into the gas-lift system or pipelines of high pressure. The solution of this problem involves obtaining a synergistic effect on additional production from reducing the pressure in the system to SBSPU and reducing the share of the gas component in the pipeline network for collecting well products.

Aim. Development of a tool based on an IT product, which is an add-on to the main model of the GAP (Petroleum Experts) collection and transport system, this tool is aimed at solving production problems of optimizing the development and operation of oil and gas fields.

Materials and methods. This article describes the calculation steps and mathematical algorithms of the MetActive IT product for determining and selecting the optimal options for optimization with the calculation of hydraulic processes occurring in the network for collecting and transporting well products based on an integrated field model built using the Petroleum Experts product package. To automate the work, the Python programming language with a library of built-in optimization algorithms and the functionality of the Open Server module in PetEx products were used.

Results. As a result of the work:

• an optimization module was developed based on the MetActive IT product, which allows searching for the most efficient sites for the installation of SBSPU and integration with the economic model;
• using the developed tool, a series of test calculations were carried out to select sites for the placement of SBSPU;
• investigated the possibility of exploitation SBSPU in combination with a mobile compressor unit (MCU) in order to compress associated petroleum gas (APG) into a gas-lift (active) gas line or monetize it with digitization of the economic effect;
• the implementation of the instrument in the structural subdivisions of the Company's subsidiary has begun with the prospect of its further development within the framework of the Asset of the Future.

Aim. Show an approach to transferring knowledge about the structural forms of stratigraphic horizons from well-studied territories to little-studied ones using generative-adversarial networks.

Materials and methods. The work uses two algorithms based on the architecture of generative adversarial neural networks. The first StyleGAN2-ADA algorithm accumulates in the latent space of the neural network semantic images of geological forms, first of the mountainous terrain, and then, using transfer learning, the forms of structures of stratigraphic horizons. The second algorithm, the Pixel2Style2Pixel encoder, using the semantic level of generalization of the first algorithm, learns to reconstruct high-resolution original images from their discrete copies (super-resolution technology).

Results. Models for reconstruction were trained, with their help, detailed depth reconstructions were obtained from maps based on 2D seismic data, comparable to the quality of maps from 3D seismic. For two sites, an assessment of the quality of reconstruction was carried out. It is proposed to create a probabilistic space of depths of the study area, where each point is represented by the density of the probability distribution of depths of equally plausible reconstructed geological forms of structural constructions of the study area/

Conclusion. The proposed approach makes it possible to create a probabilistic representation of the possible forms of the buried relief within the framework of knowledge about the already studied territory. The correctness of the reconstruction depends on the representativeness of the high-resolution data for training and on the initial structural maps for reconstruction — how accurately they reflect the dynamics of changes in the absolute elevations of the studied horizon/