This study examines the productive horizon of Miocene deposits in an oil and gas field in the Pannonian Basin (Republic of Serbia). To clarify the features of the geological structure and improve the efficiency of upcoming development of new productive areas while increasing oil recovery from existing parts of the field, the authors of this paper conducted a detailed analysis and synthesis of core data, seismic work materials, testing and the dynamics of production wells. Through conducted studies, the authors detailed the geological features of the field, updated the conceptual model, and proposed additional methods for developing the identified oil and gas reservoirs. Researches also rebuilt the geological model, adjusted the placement of the project well stock and developed a set of geological and technical measures to enhance oil recovery. Furthermore, they forecasted of development indicators. The study identified features of the field’s geological structure that suggest a “mosaic” distribution of filtration and capacitive properties within the established hydrocarbon reservoirs. The localized character of the distribution of productivity and variability of field parameters that influence the success of discovery, efficiency of involvement and development of such hydrocarbon deposits confirms the fractal properties of the geological environment. In conclusion, the authors highlighted the necessity of studying and applying the fractal properties of geological objects during oil and gas exploration.

This paper presents the results of geochemical studies on core samples from Neocomian sediments located in the northern part of Western Siberia.

In traditional geological exploration of deep-submerged facilities with complex geological structures, productive intervals are often overlooked. It underscores the necessity for additional diagnostic methods.

The aim of this work is to develop a methodological model for conducting geochemical analysis of core samples to enhance the reliability of detecting valuable hydrocarbon fluids.

To achieve this, the authors of this paper selected a set of geochemical studies on core samples, including extraction-weight analysis, chromatographic analysis, and the study of deeply sorbed gases. Based on this approach, the authors developed criteria for identifying the type of reservoir fluid in the reservoir.

The conclusions regarding the fluid saturation of the studied deposits were validated by well test results, demonstrating the effectiveness of geochemical methods in exploration efforts.

During drilling of wells using water-based drilling fluids, the filtrate can penetrate the aquifer and distorts the chemical composition and mineralization of reservoir water. Water mineralization of oil and gas bearing reservoir is used in the Archie-Dakhnov equation to calculate the oil and gas saturation coefficient. As a result, any distortion in mineralization values leads to inaccuracies in the saturation coefficient and the estimated volume of hydrocarbon reserves.

The aim of this study is to develop a methodological approach that employs genetic coefficients of water to restore the mineralization of reservoir water mixed with drilling fluid filtrates when information about the drilling fluids is available. The initial data is the chemical composition and mineralization of waters from reservoirs accessed by exploration wells. The authors of this paper applied data on chemical composition and mineralization of filtrates from drilling mud used to penetrate the aquifers. For data processing, a methodological approach based on the analysis of changes in the sodium-chloride genetic coefficient was applied to restore formation water mineralization values in their mixtures with drilling fluid filtrates. In conclusion, the authors outlined the sequence of steps for applying this approach and the requirements for the initial data needed.

Retrograde condensation is a critical process in the exploitation of gas condensate fields, leading to significant reductions in hydrocarbon production. This study examines the mechanisms behind this phenomenon, focusing on the BT₆ ¹ reservoir of the North-Chaselsky field. Here, condensation occurs when the reservoir pressure falls to 27,64 MPa, which is only 0.12 MPa above the current pressure of 27,52 MPa.

The aim of this study is to identify molecular and thermodynamic factors causing early condensation and to propose measures for maintaining reservoir pressure to reduce hydrocarbon production losses.

The paper is relevant as it clarifies the physics of intermolecular interactions during gas-liquid phase filtration in the reservoir.

Using the Peng-Robinson equation of state and Lennard-Jones potential, the authors of this paper conducted an analysis of intermolecular interactions in the methane-heavy hydrocarbon (C₅+) system. Also, the authors found that the formation of complexes with C₅+ when pressure decreases from 25 MPa down to 10–18 MPa results in the blocking of 98,9 % of the reservoir pores. This blockage is 4 to 6 times higher than the percolation threshold (15–25 %). It explains the complete cessation of gas production at the maximum condensation pressure.

The results of this work underscore the need for maintaining pressure above the dew point and managing rock wettability. This study is relevant for fields with terrigenous reservoirs, where retrograde condensation presents significant challenges to project profitability.

The premise of the study is increasing cases of negative impacts of hydraulic fracturing on nearby wells that are still being drilled, especially in areas with dense well clustering and abnormally high reservoir pressure. This paper is to identify the mechanisms of pressure and fracture propagation during hydraulic fracturing, assess their effects on the integrity of unfinished wells, and propose engineering measures to minimize risks. The leading method for the study is a combination of geomechanical and hydrodynamic modeling using KGD, PKN, and 3D fracture growth simulations, supported by analysis of real-world incidents. As a result, the authors of this paper found that under unfavorable geological and structural conditions, the fracture influence radius can exceed 300 meters, posing risks of casing damage, fluid leaks, and cross-flow between layers. In addition, the authors have developed, including adjusting well spacing, early cementing of vulnerable intervals, using monitoring systems, and performing hydraulic fracturing in stages. The practical value of this work consists in applying these findings to well design and operation to improve industrial safety and reduce accidents during simultaneous drilling and hydraulic fracturing.

Developing fields with a large gas cap and a volumetric oil rim requires continuous improvement of oil displacement technologies. This necessity arises from the heterogeneity of reservoir properties and, in some cases, unfavorable phase mobility ratios within the reservoir. Without timely adjustments in reservoir management strategies, there is a considerable risk of reduced sweep efficiency and displacement, which can lead to failure to achieve the design levels of inventory production.

 In addition to managing oil recovery in gas-supported reservoirs, the effective financial and technological utilization of associated petroleum gas is also critical. Choosing technologies that simultaneously increase oil recovery and ensure the planned use of APG is currently a priority for oil and gas companies.

This paper reviews gas and gas-chemical methods for enchancig oil recovery and assesses the potential effectiveness of these methods in the context of the Novoportovsky oil and gas condensate field.

Effective radial (horizontal) permeability is a crucial characteristic of a fluid-saturated reservoir. Understanding this parameter assists in addressing various scientific and practical challenges in the oil and gas industry.

Effective radial permeability is determined through hydrodynamic studies conducted under unsteady filtration conditions. In the current state of a developing reservoir, these methods enable the estimation of this parameter while considering the geological and field contexts at the time of measurement. However, certain circumstances — such as inadequate well shut-in time, noisy bottom-hole pressure measurements, technical problems with the lift system, or deviations from operational procedures — can lead to significant distortions in recorded time-dependent reservoir responses.

This results in ambiguous interpretations and diminishes the informative value, particularly in wells with complex completion geometries. In such cases, methods for a priori assignment of initial estimates of sought parameters, including effective permeability, before processing pressure curves become valuable and necessary. One approach involves a prediction method based on statistical models that utilize indirect indicator assessments. This paper aims to describe the sequence of steps involved in implementing an algorithm to determine initial estimates of effective radial permeability. This algorithm employs both dimensional and dimensionless criteria. They are set of quantities, which reflect the combination of geometric features of the wellbore, physicogeological properties of the reservoir, the actual energy characteristics of the production object, and field data. The paper used the conclusions drawn from geophysical and hydrodynamic studies interpretations as the initial data. This work applied mathematical statistical tools to achieve the required solutions.

The proposed methodological approach is suitable for processing pressure curves that are complicated by side effects, while ensuring reliable estimates of the effective radial permeability of the reservoir. This method can be applied to any well where the necessary data for calculations is available.

The depletion of low-viscosity and light oils forces producers to increase the development of heavy and highly viscous oils. However, traditional steady waterflooding often prove ineffective for reservoirs containing such oils. Therefore, there is a need to find inexpensive and efficient methods to improve oil recovery from these reservoirs. Cyclic waterflooding method has two main benefits: almost zero implementation cost and ease of application. This method has been widely utilized since the late 1950s in oil fields globally, including regions in Russia (Western Siberia, the Republic of Tatarstan, the Samara region, and Perm Territory), China, the United States, and the Czech Republic.

This study examines the effectiveness of two variants of cyclic waterflooding for developing reservoirs with oils of different viscosities.

The aim of this paper is to understand how oil viscosity affects oil saturation distribution within the reservoir and the overall efficiency of cyclic waterflooding.

The results of the study include an analysis of oil viscosity effects on development strategies for a two-dimensional synthetic reservoir model. These results are crucial for selecting suitable sites for cyclic waterflooding in specific oil fields.

The study shows that combining cyclic water injection with injection wells and periodic forced liquid withdrawal from production wells is the most effective modification of cyclic waterflooding. This modification facilitates the efficient development of reservoirs containing highly viscous oil.

The almost complete depletion of easily recoverable oil reserves and intensive development of reserves with complex geological structures characterize the development of oil fields today. Due to the non-standard geological structure of such reservoirs, operators face multiple challenges that do not appear with the production of easily recoverable oil. A vivid example is oil field K, which contains low-viscosity oil and has a well-permeable terrigenous pore reservoir. Initial data obtained during exploratory drilling and trial production allowed optimistic forecasts of achieving an oil recovery factor (ORF) of 0.364. However, features of the geological structure hindered the achievement of this recovery target.

This paper studies explore potential strategies for increasing oil recovery in the AB_1-2 area of oil field K.

The aim of this paper is to identify reasons for the low oil recovery at oil field K and to develop recommendations for methods, which could enhance recovery and increase the oil recovery factor.

The authors created synthetic hydrodynamic model of the AB1-2 oil object. They also performed multivariate calculations to analyze the structure of oil saturation and clarify the causes of low oil recovery.

The authors reviewed six development strategies for the AB_1-2 object model: traditional water flooding, cyclic water flooding with injection wells, cyclic water flooding with injection and production wells, and polymer flooding. The oil recovery factor values obtained in these scenarios ranged from 0,238 to 0,265. Based on the results of this study, the authors recommend to use a combination of cyclic and polymer flooding.

This paper examines the stress-strain state of a tank using data obtained through hybrid monitoring conducted in permafrost conditions. Hybrid monitoring integrates traditional geodetic surveys of the tank walls, levelling of the tank bottom, and automated settlement control of the central part of the bottom during the tank's operation.

The authors applied a numerical method using the ANSYS software environment. Also, they reviewed three calculation options: one utilizing geodetic control data for the wall and bottom, another incorporating extensometer measurements, and a third combining deformation history data of the tank along with extensometer readings.

The study found that settlements in the central bottom lead to localized zones of stress concentration in the tank wall. Additionally, accumulated deformations create an initial stress-strain state in the structure, which deteriorates as the tank continues to deform. The integration of hybrid monitoring with numerical modeling enables predictions of changes in the tank’s stress-strain state. These predictions form the basis for developing preventive measures to avert accidents.