Perm Journal of Petroleum and Mining Engineering

Basin modeling is a reconstruction of geological processes occurring in sedimentary basins using physical and mathematical apparatus, in particular, in the shell of various software. Each sedimentary basin requires an individual approach to the choice of the method for constructing a geological framework and its subsequent filling. This is due to the different tectonic structure of the regions, the stratigraphy of the sedimentary cover, the conditions of sedimentation, the volume and number of oil and gas complexes, the quality of oil and gas source rocks, etc. The choice of initial data and forecasting tools, including additional studies, depends on the level of study and the goals of modeling – sedimentation modeling and palinspastic reconstructions. The limited sample of initial information used in this case significantly affects the final forecast of oil and gas potential both at the qualitative (with a lack of data on new poorly studied territories) and quantitative (in well-studied areas to clarify the resource base within the license area or a new seismic exploration polygon) levels.In the context of the structural features of the Perm Krai, the Komi Republic and the Nenets Autonomous Okrug (Volga-Ural and Timan-Pechora oil and gas provinces), the authors consider the previously obtained experience in creating basin and sedimentation models with the overview of the important characteristics and parameters of three-dimensional models. In addition, the article describes the applied modules and methods for analyzing and processing data arrays using the Python language, which allows optimizing the stage of collecting and analyzing large, regularly updated geological information bases.

At present, when planning horizontal wells, there are a number of uncertainties associated with the accuracy of the forecast of reservoir propagation along the wellbore of a horizontal section, which largely determines the feasibility of drilling horizontal wells. The problem is particularly relevant in the context of the constant deterioration of the structure of residual oil reserves. Ultimately, the technical and economic success of drilling depends on the accuracy of this forecast.Forecasting the distribution of reservoirs along the length of a horizontal section, based only on geological modeling, does not always allow to reliably determine this value.Improving the accuracy of the forecast of trajectory in the reservoir is possible through the use of additional geological information characterizing the presence of a reservoir in the horizontal wellbore. To solve this problem, it is most appropriate to use probabilistic statistical methods. In this paper, it is proposed to use the probability of the presence of a reservoir in a horizontal wellbore (Pres), which is defined as the ratio of the penetration along the reservoir (Lres, m) to the total length of the horizontal wellbore (Lhor, m). Geological indicators that determine the presence of a reservoir in a horizontal wellbore are the coefficients of sandiness (Ks), dissection (Kdis) and effective oil-saturated formation thickness (HEff). Based on actual data, multivariate statistical models for predicting the values of Lres. were constructed.The models were developed based on data from 471 horizontal wells drilled in the Volga-Ural and Timan-Pechora oil and gas provinces.This approach makes it possible to more accurately predict the value of Pres, which can be used in planning production drilling of horizontal wells and reduces the risks of drilling inefficient wells, improves the quality of design solutions, and, consequently, increases the technical and economic indicators of the asset.

Currently, an increased interest in the discovery of previously laid down productive horizons in oil and gas fields with a long development period and in the extraction of residual oil leads to deep and thorough investigation, assessment of the mineralogical composition of rocks and lithofacies characteristic based on geological, geophysical, hydrogeological and other data.The deposits of Darwin Bank and Pirallahi Island are located in the eastward of the Absheron Peninsula, in the northwestern part of the Apsheron Archipelago, on the anticline zone of the Absheron Bank, Darwin Bank, Pirallahi Island, "Gurgandeniz".The southeastern periclinal of the Darwin Bank field borders the northern part of the Pirallahi Island field, and these two fields are separated from each other by fracture.Two fields are considered in the research work. These fields considered in the study belong to the class of long-term development fields that are in the final stages of development.These fields from a tectonic point of view belong to complicated (complex) structures. Even though it has been processed since the last century, it contains a large amount of oil reserves. For this reason, the structural and tectonic field structure, lithofacial composition, in-place and recoverable reФserves, development parameters are important. The issue we are considering is the distribution and clarification of lithofacies characteristics of the fields. The neighboring fields of the Darwin Bank and Pirallahi Islands are poorly studied and researched from the lithofacial point of view. We investigated the types of facies for the QD, QA and QaLD series of strata in the fields and compared them by compiling 3D models. As a result, changes were observed both in the areal and vertical directions.

Using the northern part of the Bashkir Arch (BA) in Perm Krai as an example, a zonal oil and gas potential forecast was developed based on a combination of generation, migration, accumulation, and conservation indicators. The relevance of the study is due to the declining efficiency of geological exploration in the highly studied area.The study aims to develop a probabilistic model for assessing zonal oil and gas potential by combining probabilistic estimates of the generation and migration of dispersed organic matter, as well as the accumulation and conservation zones of hydrocarbon deposits.It has previously been established that the generation and migration of dispersed organic matter are primarily determined by the bitumen coefficient (β, in %) and the insoluble residue (IR, in %). The accumulation of hydrocarbon deposits directly depends on the absolute elevations and thicknesses between the main reflecting horizons of the BA. The preservation of hydrocarbon deposits is controlled by the hydrogeochemical properties of formation waters, among which the mineralization and metamorphism coefficient of formation waters are of key importance.Within the framework of this work, a complex probability was developed based on the criteria characterizing the processes of generation and migration (Pgcom), accumulation (Pacom) and conservation (preservation) (Pccom) of hydrocarbon (HC) deposits. Analysis of the Pcom values for territories within the contours of HC fields (class “in contour”) and territories outside the contours of oil and gas bearing capacity (class “outside contour”) showed that this criterion is characterized by statistically different average Pcom values in the classes (0.536 – “in contour” and 0.424 – “outside contour”).A comparison of Pcom with the criteria determining the processes of generation and migration (Pgcom), accumulation (Pacom), and conservation (Pccom) of hydrocarbon deposits revealed that the accumulation criterion Pacom has the greatest influence on the Pcom (r = 0.864), followed by the generation and migration criterion Pgcom (r = 0.355). The preservation criterion Pccom has a lesser influence (r = –0.146). An analysis of the distribution of Pcom values across the study area revealed that zonal oil and gas potential probabilities Pcom greater than 0.7 units are characteristic of the southwestern part of the BA region, where large oil and gas fields are concentrated.The developed model demonstrates a relatively high predictive ability for assessing the zonal oil and gas potential of the BA territory. Characteristics associated with hydrocarbon accumulation processes (Pacom) have the greatest impact on oil and gas potential, confirming the traditional concept of hydrocarbon deposits confined to anticlinal (uplifted) structures. The study's results are applicable to predicting oil and gas accumulation zones and ranking prepared structures based on the priority of deep drilling to optimize geological exploration in the Perm Krai.

The study of sensitivity of filtration-capacitive properties to pressure is an urgent task in the planning and operation of natural reservoirs, in which cyclic changes in pore pressure inevitably occur. Among the existing laboratory methods for studying the sensitivity of rocks to pressure, there are a number of shortcomings that lead to a decrease in the accuracy of permeability prediction, especially when creating a comprehensive confining pressure. The paper presents the results of experimental studies of the effect of cyclic loads on the filtration parameters of 3D analogs of rocks manufactured by the SLA printing method with specified conductivity parameters. The mechanism of the influence of the composite structure of the model on the deformation of the filtration channel is revealed. The resulting effect of slippage of parts of 3D analogs of rocks leads to a greater narrowing of the filtration channel in the central part of the sample under cyclic application of the load. It was found that the channel located in the central part is compressed on average by 60% more than those located on the sides. The dependence of the degree of deformation of the sample on the number of loading cycles was found. It was found that during one loading cycle, the channel located in the central part of the sample narrows on average by 30% less than in the lateral part. During unloading, the channels in the central part open less, since the stored internal elastic energy is insufficient to overcome friction and shear of the halves. The results of the study show that the composite type of the design of 3D rock analogues leads to an excess of deformations parallel to the contact area over perpendicular ones. This type of design imitates the presence of relaxation cracks inherent in rock samples extracted from great depths and subject to significant stresses in natural conditions of occurrence.

The technological and economic efficiency of carbon dioxide (CO2) injection depends on many factors, such as the CO2 source, the method of gas delivery to the field, the method of injection into the reservoir, the characteristics of the reservoir and oil, etc. Therefore, before implementing the method at oil production facilities, it is necessary to conduct special laboratory tests for the conditions of oil and gas facilities, determine the technological feasibility of CO2 injection and economic feasibility. The paper presents the results of experimental studies carried out in the laboratory of modeling filtration processes and enhanced oil recovery of the Department of Oil and Gas Technologies. Using core material on the example of one of the fields in the Perm Krai, filtration tests were performed to displace oil with gas (a mixture of CO2 and methane) and joint stationary filtration of oil and gas through the porous medium of the reservoir rock. As part of the study, core and fluids were prepared, filtration tests were carried out using modern scientific equipment. Modeling of CO2 injection into oil-saturated rocks was performed on three differently permeable composite core samples. As a result, it was found that when using gas, high values of the oil displacement coefficient are achieved, due to the almost complete mutual solubility of gas and oil. Potentially, this can significantly increase the share of recoverable reserves at new objects that are just entering industrial development when CO2 injection is organized. The ratio of gas and oil in the flow at which complete miscibility occurs was determined. Cases of imbalance of the "oil - gas" system were recorded, in which heavy components of oil form resinous sediments that clog the pore space. The content of oil and gas in the flow at which colmatants were formed was determined.

The efficiency of low-flow oil wells after hydraulic fracturing is frequently compromised by residual proppant and early-phase proppant production, which can penetrate pumps and severely diminish their lifespan. Proppant management in such wells remains a persistent challenge, particularly due to the inadequate understanding of how proppant travels from the wellbore bottom to the pump intake. This study bridges that critical knowledge gap by introducing pioneering experimental findings on proppant behavior in low-flow conditions—the first to clarify the primary mechanisms at play. Using advanced laboratory simulations replicating post-fracturing environments, we observe that proppant consistently reaches the pump intake via an unnoticed process: immiscible hydrocarbon fluid droplets encapsulate and transport proppant particles upward. Key results include the revelation that the viscosity of the immiscible phase (e.g., oil or kerosene) does not significantly affect droplet transport capacity. Furthermore, proppant concentration during transport shows no correlation with well flow rates, overturning conventional assumptions. A groundbreaking insight is the role of free gas bubbles: they increase the likelihood of proppant being captured by hydrocarbon droplets, with higher gas volumes directly linked to elevated proppant levels in the flow. These conclusions are substantiated by field data from wells exhibiting high free gas content near the bottomhole, where shorter pump operational periods coincided with the proposed mechanism. By identifying this transport process, the research lays the groundwork for tailored proppant management solutions, paving the way for improved pump durability and operational performance in low-flow oil wells.

Gas hydrate formation presents significant flow assurance challenges in oil and gas operations, particularly in subsea pipelines where low temperatures (< 290 K) and high pressures (>5 MPa) create ideal conditions for crystallization. This study integrates experimental and modeling approaches to characterize methane hydrate phase equilibria, the primary component of natural gas hydrates. Controlled stepwise heating experiments (0.3–1 K/hr) in a high-pressure reactor (50–130 bar range) precisely determined dissociation conditions with temperature uncertainty of ±0.1 K and pressure accuracy of ±0.05 MPa. A novel thermodynamic framework combining the PC-SAFT equation of state for chain molecule interactions, the CPA equation for hydrogen bonding effects, and Van der Waals-Platteeuw hydrate theory demonstrated exceptional predictive capability across the 280–290 K and 5.5–13 MPa operating window. The model's robustness was validated against four independent experimental datasets, achieving average absolute deviations of 1.55% for pressure and 0.05 % for temperature with the CPA approach, outperforming PC-SAFT in high-pressure regimes.The study also investigated kinetic behavior using two experimental methods, with Method B (post-cooling gas injection) providing unambiguous induction time measurements. Results revealed critical insights into hydrate nucleation and dissociation dynamics, including the identification of equilibrium points at the intersection of heating-cooling curves. These findings advance fundamental understanding of hydrate thermodynamics while offering practical tools for pipeline design, operational optimization, and emergency response planning in Arctic and deepwater environments. The developed methodology bridges the gap between laboratory-scale data and field-scale applications, ensuring accurate hydrate stability predictions under industrial conditions.

Underground dissolution technology allows for the development of water-soluble ore deposits in areas with complex geological structures, where mining does not meet safety requirements. In the area of the Verkhnekamskoye potassium-magnesium salt deposit, productive layers are characterized by a shallow depth and increased gas content. This article is devoted to the study of the gas factor at the design stage of pilot industrial tests of the technology of underground dissolution of a carnallite deposit under the conditions of the Verkhnekamskoye salt deposit. At this site, it is planned to test the hydraulic cutting technology using a double dissolution chamber and stepwise development of the deposit. Preliminary assessments of potential gas emissions into the underground dissolution chamber were conducted. The most probable gas composition and phase states at each stage of testing were determined. It was found that the gas fraction will predominantly consist of methane, hydrogen and nitrogen, of which the first two are dangerous, as they have flammable properties. Studies of gas solubility in brine, both in the underground chamber and on the surface, showed that most of the gases will be free, accumulating under the roof of the underground chamber. A significantly smaller portion will be dissolved in the brine. It is possible that they are present in brine and in a blanket (diesel fuel) in a bubbly form. An analysis of the most probable scenarios for gases entering the hydraulic network of a surface brine production complex from an underground chamber was carried out. Dissolved and bubbly gases may enter the brine extraction line and accumulate in receiving tanks. The greatest danger is the entry of free gases into the diesel fuel line during its extraction from the underground chamber in the process of a changeover of the operating stage, followed by accumulation in the separation tank. Sections have been identified where it is advisable to limit the spread of gases along the hydraulic network paths. Technical safety barriers have been developed, which, in combination with organizational measures, will reduce the risk of negative gas factor manifestations and ensure the necessary safety of work.