Introduction. Natural fracturing is typical for carbonate rocks and plays a decisive role in the development of carbonate fractured and fractured-porous types of reservoirs. A necessary condition for successful natural fractures modeling with obtaining discrete fracture systems is the availability and interpretation in a single uniform way of the results of formation microimager logging, seismic exploration data of suitable quality and, if possible, paleoreconstruction of the geological evolution of the rock mass. In case of a lack of these data or their insufficient quality, an effective alternative may be a conceptual approach, the development and approbation of which is devoted to the article.
Aim. The purpose of this work was to analyze possible approaches to discrete fracture modeling, as well as to develop and test such an approach in the case when the use of standard methods turned out to be ineffective.
Materials and methods. Analysis of formation microimager logging and seismic exploration data allows building direct correlations of fractures parameters both for wells and making a forecast in the interwell space. In the case where the quality of available data does not allow correctly determining such dependencies and correlating fractures parameters between wells, structures and seismic attributes, a conceptual approach based on understanding the mechanism of fracture forming and propagation in ever changing geological conditions can serve as an effective alternative.
Results. The proposed approach involves developing a concept of fractures formation in a specific regional or deformation environment with its subsequent digitization and use with well information. Within the framework of this approach, an analysis of the initial data of formation microimager logging was carried out with the allocation of low-reliability intervals of interpretation and their exclusion from subsequent consideration, as well as an analysis of mud loss incidents while drilling, considering the results of 1D geomechanical modeling, to identify fractured zones bypassed by well studies. The calculated fractures parameters were stochastically distributed in the modeled area according to the distributions of fracture intensity, dip angle and strike azimuth for the previously identified petrotypes.
Conclusion. Even though the conceptual approach requires signifi cantly more efforts and competencies both in the development of the concept itself and its digitization, and in subsequent modeling, it ultimately allowed us to build a DFN model, the reliability and predictive power of which were confirmed during multiple “blind” tests for various parameters.

Introduction and aim. At the moment, there is no single document in the industry regulating the interpretation of the results of studies of samples distorted with respect to a particular state of the reservoir fluid. As a result, the absolutely correct statement that each sample carries information about the properties of the object under study is often misunderstood and the parameters of the samples are taken into averaging without analyzing their history and properties. Solving this problem is a basic task for creating a methodological and technological basis for improving the qualitative knowledge of reservoir fluids.

Materials and methods. The methods of a systematic approach, expert survey and thought experiment were used in the development.

Results. A terminological system is presented to describe the process of interpreting fluid information; correlations used in this analysis are classified; a typology of distortions in the properties of reservoir oil and some areas of its application are proposed.

Conclusion. It is recommended to use the proposals in the It is recommended to use the proposals in the Development of normative and methodological documentation in the fi eld of expert examination of the properties of reservoir fluids.

Aim. The paper presents examples of the results of assessments of the properties of the initial reservoir oil in the study of distorted samples of reservoir fluids.

Methods. Sampled:

1) Downhole samples of non-volatile oil in the conditions of a gushing inflow of the first well.

2) Wellhead samples of volatile oil in conditions of a gushing inflow of depleted reservoir.

A set of standard PVT analysis was performed on the samples. The wellhead samples were recombined using a heuristic algorithm developed by the authors for calculating the composition of a component-by-component recombination gas.

Results. The application of the methodology for working with samples taken in multiphase flows is illustrated. Recommendations are given on some optimal set of studies.

Conclusion. the results of the work are recommended to be used in the development of educational materials and taken into account when planning work on sampling reservoir fluids.

Introduction. Energy distribution at a hydrocarbon pay is a very important part of reservoir development analysis with a strong impact on production performance. Estimating formation pressure across the field is a highly important routine procedure which is unfortunately very costly due to production deferment during the well shutin for pressure survey.

Goal. To provide the methodology and case study of the estimation of formation pressure based on deconvolution of the long-term permanent downhole pressure monitoring and its correlation with the offset wells production history.

Materials and methods. The formation pressure estimation is based on a multi-well pressure-rate relationship for a given group of wells. The pressure-rate model is based on convolution of pressure transient self-response and pressure transient cross-well responses with rate histories. The pressure transient responses are deconvolved for the historical records of permanent downhole pressure gauges. Deconvolution formation pressure is a self-validated methodology, which means it can check is own accuracy during well production. The moment a bottom-hole pressure from convolution pressure-rate model prediction starts deviates from historical records substantially one should repeat the deconvolution process form this historical moment onwards and provide the new set of model parameters for the rest of the production history.

Results. The technology has been developed for reservoir pressure evaluation using multi-well deconvolution without actual well shut-ins.

Conclusion. Deconvolutional formation pressure, as the basis of modern reservoir surveillance programs, allows operators to reduce costs by providing an opportunity to predict the value of reservoir pressure in real time without production deferment.

Introduction. In modern conditions, the limitations of oil production associated with OPEC+ make it urgent to redistribute production between wells in order to reduce the water content of products and unload the collection network. Making decisions about the optimal distribution of flow rates is often complicated by the interference of wells, which can affect each other both through the reservoir and through the collection system. Therefore, to optimize the operation of the fishery, it is advisable to use multivariate calculations based on an address integrated model.

Aim. In order to optimize the operation of the field in conditions of limited OPEC+ oil production, a full-scale integrated field model was built, adapted and used in development monitoring.

Materials and methods. To build an integrated model of an oil field at a late stage of development, optimal methods for accounting for producing wells in periodic operation, modeling paraffin deposition processes, tools for modeling wells with leaks, accounting for joint wells developing several EOS simultaneously are proposed. The full-scale integrated non-isothermal model of the field includes 7 hydrodynamic models, more than 400 models of producing and injection wells, models of the absorption system, a model of the PPD system including local injection, models of secondary development facilities and the Cenomanian aquifer constructed by the material balance method. The main feature of the implemented model is a large fund of operating wells, the periodic nature of the work of a significant part of the fund, many leaks, as well as complications associated with the loss of paraffins.

Results. The applied methods of optimization of the integrated model made it possible to carry out multivariate calculations with the implementation of various strategies for entering the fi eld into the OPEC+ production limits according to the most economically profitable scenario. The high calculation speed of a full-scale integrated fi eld model has allowed us to create a useful additional development monitoring tool.

Conclusion. The results obtained confirm the effectiveness of using a full-scale integrated model of an oil field at a late stage when monitoring development and making decisions.

Introduction. The aggressive injection pressure resulting in spontaneous hydraulic fractures in injection wells improves the process of maintaining reservoir pressure in low-permeability reservoirs. However, the instability of fracture development may adversely affect field development by disrupting the uniformity of displacement, creating a hydrodynamic connection between adjacent areas, and leading to uncontrolled water breakthrough to producing wells.
Aim. The goal of the study is to identify and comprehensively analyze the causes of the sharp water production increase in producing wells following the implementation of injection pressures with the induced fracture in an injection well, using the example of a field with several licensed areas.
Materials and methods. This work utilized pressure transient analysis and production logging interpretation results, petrophysics, tracer tests, and 6K analysis of the produced fluid composition. In addition, analytical modeling was applied to evaluate parameters such as the formation bedding angle, and a calculation of spontaneous hydraulic fracture propagation was performed.
Results. Data analysis allowed for the consideration of all potential causes of the observed phenomenon and confirmed the existence of well interference between license areas. It was established that the spontaneous hydraulic fracture, occurring in injection wells on an adjacent area, led to the formation of an extensive fracture that crossed the boundaries of the licensed areas and facilitated the influx of water into the producing wells.
Conclusions. The study revealed that for a correct interpretation of the production logging, the formation bedding angle should be taken into account. It also emphasized the importance of a comprehensive analysis of neighboring areas prior to conducting any operations. The risk of direct water breakthrough from injectors to producers through spontaneous hydraulic fracture, even over large distances, has been confirmed on a low permeable asset.

Introduction. Nowadays one of the strongest challenges for oil industry is hydrocarbon residual reserves localization in the cross-well space at mature oilfields. 
Goal. The paper describes the cross-well reservoir tests for the most promising oil-saturated areas revealing and drilling infill wells and sidetracks to increase oil recovery. Another purpose of the study is to assess the water fiooding system efficiency and quantify its impact on surrounding producer wells.
Materials and methods. The cross-well reservoir scanning at the mature oilfield was performed by the pulse code testing technology. It is a special kind of pressure interference testing. The study involves one generator well and several receiving wells. Generator well dramatical changing the rate and it creates pressure pulses, which propagate through the reservoir and are registered by high-accuracy quarts pressure gauges at the receiving wells. The key advantage of the technology is the creation of a special pressure “code” in a generator well by injection and shut-in periods of different durations. This special code allows to decompose the receivers’ pressure recording and recognize only the pressure variation connected to the generator rate changes. This allows not to shut oil producers during the test, as the particular pressure response can be revealed even in a presence of strong pressure noise of different nature. pressure response can be interpreted and water-oil displacement efficiency between wells can be assessed.
Results. The study quantified the pressure impact of the generator well on the surrounding wells. Also, the current reservoir pressure in tested wells was evaluated. The study also assessed connected net-pay thickness and current saturation in a cross–well space.
Conclusion. Based on results it was recommended to drill sidetrack from one of the pressure observation wells to increase the production and recovery. It was performed and oil production from the well confirmed high economic efficiency of these operations at the studied field, despite the already very high current oil recovery.

Background. In 2023-2024, in order to prevent intercasing pressure, a decision was made to conduct pilot work, which consisted of using self-healing cement when cementing production columns Ø178 mm and combined Ø140x178 mm without using a casing packer. It is worth noting that the use of cement designs with design parameters corresponding to the technical specifications and the use of a casing packer does not always ensure reliable formation waterproofing and the absence of inter-column space leaks (ICL) and intercasing pressure.
Aim. The purpose of this article is to highlight the practical experience of using self-healing cement to prevent the occurrence of intercasing pressure and behind the casing flow.
Materials and methods. Testing of self-healing cement mortar stone was carried out on certified equipment in accordance with the requirements of API 10B-2, API 10B-5 standards, tests of elastic strength properties were carried out in accordance with GOST 21153.8-88 “Rocks. Method for Determining the Ultimate Strength under Volume Compression”, studies of the filtration and capacity properties of cement stone were carried out in accordance with the recommendations of GOST 26450.2-85 Rocks. Method for Determining the Absolute Gas Permeability Coefficient during Stationary and Non-stationary Filtration.
Results. Based on the results of the pilot project without using a casing packer at the current field, the efficiency of using self-healing cements was proven. The increase in the continuous contact interval for 178 mm production columns was 20%. Intercasing pressure was recorded in 3 wells out of 5 after putting into production and performing well servicing operations, however, when releasing pressure from the annular space, the annular pressure decreases to 0 atm, which confirms the ability of cement stone to self-heal.
Conclusions. Self-healing cement technology has proven its effectiveness in real-world conditions, improving the overall quality of cementing and reducing the intensity of intercasing pressure due to its self-healing properties when in contact with hydrocarbons.

Introduction. The development of oil fields located in remote, hard-to-reach areas with a lack of developed infrastructure for external transportation of oil and gas is complicated by the problem of associated petroleum gas utilization. Optimizing this process requires selecting the number of injection wells and estimating the maximum injection well efficiency.
Aim. Estimation of the maximum efficiency of injection wells for the reverse injection of produced associated petroleum gas.
Materials and methods. Analysis of geological and geophysical information on the field and application of existing international experience in determining the efficiency of gas injection wells.
Results. Using the example of an oil and gas field, the approach is described, and examples of calculations for determining the maximum intake capacity of gas injection wells are given.
Conclusion. The maximum efficiency and required number of gas injection wells for utilization of the produced associated petroleum gas into the reservoir have been determined.

Introduction. In conditions of high gas factor of the extracted products, the urgent task is to find new solutions for gas utilization. Within the framework of this work, the analysis of existing solutions for utilization was carried out, and it is proposed to use in a new way the technology of using a wellhead jet device (ejector) for pumping associated petroleum gas back into the formation using injection wells.
Aim. Development of a new technical solution for the utilization of associated petroleum gas.
Materials and methods. The current operating modes of the wells, as well as data on the geometric parameters of the wellhead jet device, were used as initial data. A package of macros in the VBA programming language was used to perform the calculations and steady state and transient well simulation.
Results. A new method for the utilization of associated petroleum gas was proposed, the optimal design of the wellhead jet device was selected, a universal tool for analyzing the operating modes of the ejector was created, and the effectiveness of the proposed solution was experimentally proven.
Conclusion. As a result of the analysis, calculations and pilot tests, it was determined that the wellhead jet device is an effective method for utilizing associated petroleum gas.

Introduction. As with any structure, there may be a need for repairs during operation for a wide range of reasons, including as a result of both internal and external influences (trawl, etc.).
Aim. To propose a new method, alternative to the traditional one (the pipeline is welded above the water surface and then put down to the bottom being curved) for repairing an underwater marine pipeline damaged to the point of complete rupture of the pipe, provided that both ends of the pipeline can be raised above the water surface at the point of damage.
Materials and methods. Analysis of existing solutions, estimates, expert assessments
Results. A method for repairing underwater pipelines without welding under water surface, based on a flange connection, is proposed.
Conclusion. Conducting preliminary studies have shown the real feasibility of the proposed method. However, given that it is being used for the first time, detailed clarification of individual solutions is required.

Introduction. One of the key issues at the front-end development phase for gas and condensate fields refers to selection of the most economically effective processing technology for natural and associated gas. Justification of the optimal solution is a complex technical and economic task that requires significant effort from a team of experts.
Aim. The purpose of this paper is to present a digital tool based on multi-agent technologies that form a flexible and adaptive system of many elements that interact with each other to achieve a common goal.
Materials and methods. Methods of system engineering, intelligent multi-agent technologies, surrogate modeling (AI-based proxy models) are used.
Results. This paper presents results of development of the digital tool that determines the optimal temperature for low-temperature condensation processes (LTC) providing the optimal output of commercial products, with consideration of necessary technologies and transport environment/capabilities.
Conclusion. The prototype of abovementioned digital tool is useable at the stages of conceptual design for solving problems related to selection of gas treatment technology.

Introduction. Integrated simulation is a modern approach to managing oil and gas assets, which allows combining various aspects of field development into a single model. This method becomes particularly relevant at the late stages of field development when it is necessary to optimize production and maximize the efficient use of the remaining reserves. The paper discusses prospects for applying integrated simulation for mature fields.
Aim. The research is aimed at studying the prospects for application of integrated simulation for mature oil and gas fields. The main goal is to present promising methods and technologies for the development of integrated simulation as a coherent system composed of individual components, as well as the use of integrated models to optimize production, manage infrastructure, and improve economic efficiency under significant uncertainty and complications.
Materials and methods. The paper analyzes modern approaches to simulation of the integrated system “reservoir-well-surface network.” Methods of automated development and history-matching of geologic and reservoir simulation models, as well as surface infras tructure models, are used. The paper presents typical applications of these methods to identify, localize, and address technical challenges aimed at improving production management quality.
Results. Integrated models provide to optimize well operation modes, manage liquid and gas inflows, improve surface infrastructure. Examples with successful implementation of both the integrated model itself and the automation and optimization methods described in the article confirm the high efficiency and relevance of this approach.
Conclusion. Integrated modeling allows to significantly increase the accuracy of forecasts and production efficiency, however, it leads to an increase in labor costs for its creation. In order to reduce labor costs, develop post-processing of calculation results, specialists of the Modeling Center have developed optimization algorithms. The algorithms allow to optimize the stages of creating models, calculating scenarios and processing results. The experience of other companies was considered in order to outline the vector of further development of their own developments in the part of IM.

Introduction. This paper addresses the urgent problem of monitoring the condition of field pipelines in the oil and gas industry, where corrosion defects significantly affect operational efficiency. Traditional methods of assessing pipeline networks, such as in-line inspection and corrosion coupons, have technological and economic limitations. This study proposes a novel approach based on machine learning methods to predict defect growth using retrospective data.
Objective. The aim of the research is to develop a pipeline remaining life prediction tool based on machine learning methods to improve pipeline integrity management. The main task is to create an algorithm capable of forecasting the emergence and development of corrosion defects, thereby enhancing the reliability of pipeline transport, reducing operational costs, and optimizing maintenance processes.
Materials and methods. The study utilized data on the technical condition of pipelines, including results from in-line inspection (ILI), ultrasonic thickness measurements (UTM), and operational parameters. The following machine learning methods were applied for analysis and forecasting: gradient boosting (CatBoost), AutoML, LSTM, and Transformer. Data preprocessing included the selection of key parameters using Pearson correlation analysis and principal component analysis (PCA). The data was split into training and test sets, and the effectiveness of the methods was evaluated using the Mean Absolute Error (MAE) metric.
Results. A comparative analysis of various machine learning algorithms was conducted to predict the depth of corrosion defects in pipelines. The best performance was demonstrated by the model based on gradient boosting combined with a Transformer architecture. 
Conclusion. The developed tool enables early defect detection, automated in-depth analysis of large datasets, and decision-making support. Implementing this approach in operational processes helps reduce inspection and repair costs and improves the safety of oilfield pipeline operations. The tool can be integrated into pipeline condition management systems to provide effective forecasting and maintenance planning.

Introduction. Modern business is facing new challenges and increasing requirements for the efficiency of field development management, including the solution of complex, integrated and massive problems under uncertainty of external conditions. The evolution of information technology (IT) is opening up new opportunities for scaling high-performance computing and implementing digital solutions, which is particularly important for multivariate field development prediction.
Aim. Improvement of methods for solving multivariate problems on the basis of changing approaches to formulating the model description and managing the computation workflow using the developed dynamic simulator. The main tasks are to search for approaches to effectively solve multivariate problems, to implement these approaches, and to verify their performance and prospectivity.
Methods and approaches. To automate the solution of multivariate problems based on the author’s simulator, the integration of the Lua scripting language into the simulator kernel, the creation of an alternative input data format and the extraction of the internal computational workflow into the script space are proposed. In order to maintain high performance of calculations, the optimal division of functionality between the interpreted and compiled parts of the simulator is organized.
Results. A hybrid simulator with an integrated scripting environment was developed; its efficiency was demonstrated by using an alternative data input format, extending the functionality to model complex reservoirs, creating fully “random” models, and describing a set of stochastic models in a single input file. It has been observed that in auto-history-matching and optimization problems, there is a simplification in the construction of multi-realization scenarios, both for external launcher programs and for the implementation of digital development strategies.
Conclusion. Successful integration of the high-level programming language with the author’s simulator demonstrated a new level of simulator control, creation of flexible and dynamic input data format, automation of multivariate task preparation, possibility of creating digital strategies for field development.