Introduction. In petroleum geology, heavy mineral analysis is an important tool for reconstructing sediment provenance, transport conditions, and diagenetic history of terrigenous rocks. However, the classical optical method has certain limitations that can be overcome by Raman spectroscopy, as this technique enables reliable identification of both transparent and opaque as well as well-rounded grains, and allows the detection of polymorphic modifications and micron-sized minerals. This significantly enhances the informational value of heavy mineral studies compared to conventional optical microscopy. The method was applied to wells drilled on the northeastern Sakhalin shelf—a key petroleum-bearing region with Neogene terrigenous reservoirs that have been only poorly investigated in terms of their heavy mineral composition.

Aim. To study the composition of heavy mineral assemblages in sandstones of the Neogene petroleumbearing succession (Nutov Horizon) on the northeastern Sakhalin shelf using Raman spectroscopy on core and cuttings samples from wells located at varying distances from the coast, in order to assess source area position, mineralogical maturity, and spatial variations in composition.

Materials and methods. A Raman spectroscopy study was carried out on core and drill cuttings material from the Nutov Horizon (Miocene–Pliocene) across five wells representing various fields on the northeastern shelf of Sakhalin Island.

Results. The results confi rm the assumption of a common provenance for the Lower and Upper Nutov deposits and indicate the proximal position of the source area. The identified heavy mineral associations can serve in the future as diagnostic markers for distinguishing between Lower and Upper Nutov subhorizons in well sections— particularly useful for young Neogene sediments that are difficult to stratify in the absence of index fossils, as well as for attributing core or cuttings samples that have lost their descriptive documentation.

Conclusion. Raman spectroscopy is an informative method for characterizing sediment provenance.

Introduction. Currently, most oil fields are in the late stages of development, where the issue of reevaluating cross-well reservoir properties to enhance the recovery of residual hydrocarbon reserves and achieve the target final oil recovery factor becomes particularly acute. Permanent geological and hydrodynamic models, which are most often used to select areas for infill drilling or other production enhancement operations, do not always possess high predictive capability. Consequently, there is a pressing need for methods to calibrate and improve the predictive capability of geological and hydrodynamic models.

Aim. To improve the predictive capability of geological and hydrodynamic models, multi-well hydrodynamic tests (interference testing) were conducted. Based on the results, the permeability of the inter-well space was calibrated, which in turn aff ects the distribution of residual hydrocarbon reserves.

Materials and methods. The methods for achieving the set goal involve conducting pressure interference testing to compare the actual reservoir properties of the inter-well space with the model ones; subsequently, based on the obtained results, a decision of geological and hydrodynamic model recalibration is made.

Results. Following the recalibration of the petrophysical model, permeability was propagated in the geological and hydrodynamic model, and recommendations for infill drilling were issued based on the new distribution of residual hydrocarbon reserves. The actual drilled well confirmed the presence of residual reserves in the predicted zone.

Conclusion. The obtained results confirm that this approach can serve as a reliable basis for calibrating geological and hydrodynamic models to improve their predictive forecasting capability.

Introduction. The problem of identifying and assessing the mutual influence of wells is one of the key issues in the modern oil and gas industry and the least studied in relation to the conditions of gushing oil production. Forecasting well production volumes, planning well commissioning/decommissioning, and changing their operating modes is impossible without a clear understanding of these interactions.

Aim. The objective of this review is to analyze the applicability of existing models for assessing the interaction of well operating parameters under flowing oil production, based on published sources.

Methods. Articles for the review were selected according to the PRISMA methodology using keywords in the Google Scholar and Elibrary databases. Available full-text articles were manually screened for relevance to the research question.

Results. The review included 25 publications that matched the search query. Their analysis revealed a fairly wide range of applied methods and models: the hydrodynamic modeling method, the experimental method, the material balance model, the capacitance-resistance model (CRM), the two-dimensional filtration model, spatially autoregressive models (SAR, SEM, etc.), the spatiotemporal autoregressive moving average model (STARMA), the time series analysis (TSA) model, the vector autoregressive (VAR) model, and the Bayesian vector autoregressive (BVAR) model. Each of them has its own disadvantages, such as labor intensity, high cost, computational complexity, and sensitivity to gaps and outliers in the data. Many of them require certain assumptions and adaptations to assess the well-to-well relationships during flowing production. An analysis of the advantages and disadvantages led to the conclusion that the vector autoregressive model is the most promising for assessing the mutual influence of well oil flow rates during flowing production.

Conclusion. A wide range of well interference analysis methods allows for selecting a method that takes into account existing research limitations, but in all cases they require adaptation to flowing production.

Introduction. Due to the strong difference between carbonate reservoirs and terrigenous reservoirs in the structure of the pore space and other properties, these deposits require special approaches to study. For this reason, the authors have been conducting methodological work in this area in recent years. This work is a summary and summarizes the accumulated experience of the authors in the field of capillary core investigations of carbonate reservoirs.

Aim. To develop practical recommendations for laboratories. To determine the directions for further improvement of methods for studying capillary properties and carbonate deposits.

Materials and methods. The semipermeable membrane method (study of capillary properties) was used as the main method. The following methods were used as auxiliary methods: centrifugation (capillary properties), gasvolumetric (open porosity), liquid saturation (pore volume) and layered NMR (water distribution in the sample). The capillary palette method was used to generalize the capillary curves. The studies were carried out mainly on limestones of Eastern Siberia (Nepsko-Botuobinskaya anteclise, Lower Cambrian, Osinsky horizon) and other regions with fractured-cavernous and intercrystalline types of porosity. Samples with a diameter of 38 mm and a length of 50–60 mm were used.

Results and conclusions. As a result of the work carried out, the experience of capillary studies of carbonate rocks was generalized. The main problems and factors affecting the quality of measurement results are described. The directions of further development of the methods were outlined. Practical recommendations on performing experiments and processing the results are given.

Introduction. To date, for almost all oil and gas producing companies, the issue of maintaining production from the current wells is relevant. Understanding both the current reservoir pressure and its distribution across the development targets, as well as the dynamics of reservoir pressure in the past, is one of the most important sources of information when analyzing field development to identify opportunities for maintaining production. At the same time, the standard approach to determining reservoir pressure requires shutting in wells, which leads to production deferment.

Aim. To improve the efficiency of field development and clarify information on current reservoir pressure, reservoir pressure calculations were performed using multiwell deconvolution, conducted based on the results of long-term monitoring of bottomhole pressure and flow rate of a group of wells during their production.

Materials and methods. The method for achieving this objective is to use a mathematical algorithm for multiwell deconvolution to quantitatively assess the impact of production of each well in the group on the bottomhole pressure in the central well. Once this relationship is established, it becomes possible to mathematically shut-in the central well and obtain its reservoir pressure without actually shutting it in.

Results. The technology was tested on a terrigenous field with a gas cap, produced by horizontal wells. Based on long-term bottomhole pressure monitoring, multiwell deconvolution was performed, reservoir pressure was calculated, and its prediction was made. Based on subsequent monitoring, reservoir pressure was recalculated, and the discrepancy between the predicted and actual values was just a bit over 1 %. Additionally, the reservoir and near-wellbore zone properties, drainage area size, and cross-well pressure interference were assessed.

Conclusion. The obtained results confirm that the authors' approach can serve as a solod basis for reservoir pressure monitoring in conditions where studies required by standard approaches becomes almost impossible due to production deferment, such as in case of horizontal wells, producing from low-permeability formations.

Introduction. The gradual advancement of well drilling and completion technologies necessitates the parallel development of well testing technology. With declining reserve quality, the goal-setting of well testing is being adjusted, and understanding the efficiency of well construction and operation with hydraulic fracturing is currently becoming paramount.

Objective. Developing a classical approach to well testing as applied to hydraulically fractured wells.

Materials and methods. New concepts are used: complex flow parameter, complex capacitance parameter, and a dimensionless invariant relationship between these parameters for subsequent use in data interpretation.

Results. A new approach to data interpretation has been developed, enabling interpretation in the absence of late pseudoradial flow in hydraulically fractured wells.

Conclusion. A new well data processing methodology has been developed, significantly reducing survey time and significantly increasing the information content of well testing in hydraulically fractured wells.

Introduction. In the context of depleting accessible reserves, enhanced oil recovery methods remain critically important for a range of fields, often transforming from experimental technologies into a mandatory tool for the eff ective development of brownfields and ensuring energy security.

Objective. The aim of this work was to optimize the process of screening effective enhanced oil recovery (EOR) methods based on industry application experience, and to test the developed algorithm on a carbonate fractured reservoir.

Materials and methods. To determine optimal EOR methods, the author developed a specialized rapid assessment methodology for evaluating the applicability of various technologies, based on a unique database. The key element of the tool is a criteria-based assessment of the applicability of different EOR methods and their ranking depending on the geological and geophysical properties of the reservoir, combined with an assessment of the industrial maturity of the selected stimulation technologies.

Results. New methodology significantly reduces the time and operational costs of EOR method screening, identifies geological limitations at the earliest stages, and optimizes further work on selecting an effective stimulation technology. The methodology is implemented as an application and is based on a comprehensive database of EOR application success rates in the industry.

Conclusion. The new approach has demonstrated efficiency and rapidity in determining reservoir stimulation technologies. Using a carbonate reservoir field as an example, the signifi cant influence of fracturing on the potential success of gas-based EOR methods is shown.

Introduction. Tracer studies (SWCTT) with the injection of surfactant-polymer composition were carried out at a single well of the Sutorminskoye field. The surfactant tested was the enhanced oil recovery agent Sibex Oil & Gas SRF 1000 (Technical Specifications 20.59.59-005-67278822-2025) produced by “ZILANT OIL TECHNOLOGIES” LLC (right holder: SIBUR Holding PJSC).

Aim. Assessment of the efficiency of the newly synthesized surfactant within the surfactant-polymer composition for reducing residual oil saturation and increasing the oil recovery factor.

Materials and methods. The field studies employed a new approach involving the injection of a pre-prepared tracer triplet into a single well, which represents a mixture of a primary tracer, a cover tracer, and a backup tracer. A previously published methodology for determining the well shut-in time (technological settling time for the ester hydrolysis reaction) was successfully tested.

Results. As a result of the surfactant-polymer flooding operations, a reduction in residual oil saturation at the single well was established from 0.233 to 0.116, which corresponds to an increase in the oil recovery factor by 19.1 %.

Conclusion. The data obtained indicate the high efficiency of the newly synthesized surfactant and the viability of the proposed methodological approach using a tracer triplet for monitoring oil displacement processes.

Introduction. At present, the oil and gas production industry is facing a number of challenges in the development of hydrocarbon fields. This is mainly due to the fact that a large proportion of fields are at a late stage of development. High water cut, low flow rates and declining reservoir pressure lead to increasing technological risks and the need for new technical solutions.

Aim. The aim of this work is to analyse the main complicating factors arising during the operation of hydrocarbon fields within the Gazprom neft companу group and to present the technical solutions applied to prevent them and reduce their impact.

Materials and methods. The study is based on indicators of the producing well stock of the Gazprom neft companу group, including the share of wells complicated by high gas–oil ratio, asphalt–resin–paraffin deposits (ARPD) and solids production. The analysis is performed by generalising field operation experience and using artificial lift systems and specialised monitoring systems.

Results. It has been established that within the company’s assets about 44 % of wells are complicated by high gas–oil ratio, about 33 % by ARPD, and solids production is observed in approximately 28 % of the well stock. To mitigate ARPD, modules for heat loss compensation are used, and thermoelectric units and inhibitor injection systems are being improved. For the operation of wells with high gas–oil ratio, electric submersible pump systems adapted to high gas content and energy-efficient gas separators are being implemented. Under conditions of solids production, multiphase flow metering units, new-generation sensors and modified complex downhole filter designs are applied.

Conclusion. The key complicating factors in the operation of fields within the Gazprom neft companу group are considered, and technical solutions for their prevention and mitigation of their consequences are presented, which confirms the effectiveness of an integrated approach and can be taken into account when optimising production systems at late-stage fields.

Introductuion. Maximizing the effective borehole length in a productive formation is a key measure for developing additional hydrocarbon reserves. Improving geosteering efficiency directly depends on the accurate aligning of logging data with seismic forecasts of the target formation. This work addresses the narrowing of the spatial uncertainty corridor by quickly comparing logging-while-drilling data with alternative depth-velocity models, enabling continuous refi nement of the target formations hypsometric position.

Aim. This paper aims to improve the efficiency of horizontal well geosteering by minimizing the uncertainty of the wellbore's spatial position relative to the seismic forecast within the target formation. The paper examines the construction of alternative depth-velocity models (DVM) that generate a confidence range for the forecast. Regular verification of the algorithms accuracy is required to ensure their proper operation. A key element in confirming the seismic forecast is the iterative comparison of logging-while-drilling (LWD) data with predicted seismic volumes, which allows for a consistent narrowing of the uncertainty corridor and refinement of the hypsometric position of the producing structure. Reducing measurement errors directly impacts the overall efficiency of the process. This real-time iterative procedure is aimed at maximizing the effective penetration length of the target object and involving additional hydrocarbon reserves in development.

Materials and methods. The source materials included seismic cubes, well logging data, well logging interpretation, density image interpretation, and well directional surveys. The primary research method was numerical modeling.

Results. Based on a case study of a horizontal well, the possibility of minimizing the uncertainty of horizontal wellbore positioning during geosteering was demonstrated. Practical implementation allowed for minimizing the uncertainty of the depth-velocity model, reducing inefficient drilling, and increasing geosteering efficiency.

Conclusions. The effectiveness of using seismic data to minimize horizontal wellbore positioning uncertainty was confirmed during the drilling of a production well penetrating productive sediments of coastal-continental origin. Practical implementation of an iterative procedure for correlating LWD data with seismic data ensured high convergence of the results, allowing for the reliable determination of the horizontal section's trajectory on the seismic section. The established relationship served as the basis for subsequent operational adjustments to the drilling trajectory. Integrating seismic data into the well guidance process enables a transition from a reactive geosteering model to proactive well guidance. Implementing these solutions into the geosteering process optimizes well guidance, maximizes the volume of hydrocarbon reserves recovered, and reduces the risk of accidents and liner failures.

Inroduction. Recovering remaining reserves in Valanginian formations at late stages of gas condensate field development is a complex task requiring innovative and effective approaches and solutions. The number of flooded wells with low reservoir pressure at the gas condensate field in the Yamalo-Nenets Autonomous Okrug is constantly increasing, resulting in a growing pool of idled wells. Currently, over 40 % of the total number of producing wells are idle or inactive due to water cuts. When reactivating wells, well owner face complications typically related to declining reservoir flow characteristics and the imperfections of existing well cleanup methods under abnormally low reservoir pressure (ALRP). This results in a low success rate for such operations (27 %). At the same time, the presence of significant residual recoverable reserves in the idled well necessitates the improving the effectiveness of well cleanup efforts.

Aim. To improve the efficiency of well reactivation, the authors developed and tested an approach to restarting idled Valanginian wells using direct (noncompressor) gas lift from the Achimov donor well. The primary objectives of this study were to investigate the feasibility of this approach and validate its effectiveness on digital twins and real wells.

Materials and methods. The choice of noncompressor gas lift as a cleanup method was based on the near location of the high-pressure Achimov wells to the inactive wells of the studied field. To validate the feasibility of the proposed well reactivation technology, a performance assessment approach using dynamic flow transient modeling was applied.

Results. Following successful testing at the first well, the proposed approach and mentioned cleanup plan were implemented at four additional inactive wells. While the second well also yielded positive results, the next three wells failed due to geological issues (excessive water influx and reduced reservoir properties).

Conclusion. The obtained results confirm the viability of the proposed cleanup method with an efficiency assessment using the developed dynamic modeling approach.

Introduction. Acceleration of reservoir simulation is necessary to reduce uncertainty and improve the quality of investment decisions in field development.

Objective. Study of the possibility of accelerating reservoir simulation without increasing hardware capacities: by adjusting convergence parameters and model properties (smoothing properties based on outlier detection filters, "additional" property upscaling).

Materials and methods. The SimBoost soft ware package has been developed, which includes various approaches to reducing calculation time and error control. It was tested on the company's simulation models: each method was tested individually and also in combination with other methods.

Results. It was shown that acceleration depends on calculating error method and model properties. The average acceleration due to the adjustment of convergence parameters is 30 % in the case of an error analysis based on the total flow rate and average pressure in model, and 16 % in the case of an error analysis based on flow rate and bottom-hole pressure in each well. One can also increase the acceleration if additionally adjust the properties of the model.

Conclusions. SimBoost soft ware implements algorithms for adjustment convergence parameters and correcting model properties. Combining different acceleration methods to achieve the best result seems promising. Therefore, it is planned to develop SimBoost as a comprehensive solution that allows users to build the acceleration process using various methods.

Introduction. Adaptation of Integrated Asset Model (IAM) component models is an important step in the creation of a mathematical model of an oil and gas field. Correct adaptation allows for the generation of production profiles that take into account all infrastructure constraints and bottlenecks in the production system. Through the large-scale integration of development tools, application programming interfaces, integrated modeling tool suites, and real-time data management tools, solutions for the rapid and automated adaptation (auto-adaptation) of oil and gas asset models can be implemented.

Aim. The aim of this study is to describe a methodology for automated history matching of reservoir (material balance model), well, and gathering and transport network models (GTN), as well as experience implementing them in a soft ware product.

Materials and methods. The source materials for this study were drawn from the many years of experience and best practices of subject matter experts collected by the authors, as well as synthetic and existing production model components of the IAM of varying complexity, to formalize a unique method for identifying tuning parameters. To optimize calculations based on these methods, a modular computational and analytical soft ware package was implemented in the Python programming language. Testing of the methods and modules of the package was conducted on facility models of the Company's production entities, including Gazpromneft -Khantos, Gazpromneft -Vostok, and Gazpromneft -Orenburg.

Results. The methods and modules used in this study solve the problem of automated history matching of material balance, well, and GTN models without the need for a subject matter expert to directly participate in the history matching process. The methodology and modules for automatic model matching enable models to be tuned to current actual data with a minimum number of model runs. Auxiliary modules help assess the quality of the history matching process and the final convergence of calculated model indicator values with actual data.

Conclusion. The advantages of the algorithms include: 1) automation of the history matching process; 2) a wide range of supported types and parameters for component model matching; 3) speed of reservoir and GTN models matching after a small number of model runs; 4) scalability of the soft ware package and universality of approaches for a large number of integrated modeling tools (including domestic import-independent soft ware). The acceptable error level of automated matching process for all model types was determined. The results of the calculation and analytical soft ware package allow us to conclude that the proposed solution is effective and demonstrate the importance of automating the history matching process.