The subject of the study is viscous instability (viscous fingering) of the displacement front that arises under an unfavorable mobility ratio during waterflooding of heavy oil reservoirs, and the ways to account for it in reservoir simulation. The aim of the work is a quantitative assessment of the reproduction of viscous instability on computational grids of different resolution, identification of the limitations of numerical formulations, and substantiation of the concept of coarse-grid accounting through calibrated pseudo-displacement parameters. The open-source simulator porousMultiphaseFoam (PMF), built on the OpenFOAM platform, was used as the reference tool; an industrial (commercial) reservoir simulator was used for comparison. Two series of numerical experiments were performed: a direct comparison of the two simulators on an identical heavy-oil displacement problem, and a study of the influence of the grid block size in PMF under an unchanged physical formulation. The comparison was carried out by water-saturation fields and integral production indicators – oil and water production dynamics, water cut, and the oil recovery factor. It was found that a continuum two-phase formulation in a homogeneous medium without an explicit source of perturbations does not initiate fingering, while the inherent numerical diffusion of finite-volume schemes suppresses viscous fingers; with sufficient grid refinement the instability appears and substantially reduces the predicted oil recovery factor. The results justify the need to construct pseudo-displacement parameters for full-field models. The results are applicable in the design of waterflooding systems and enhanced oil recovery methods at heavy-oil fields.

The article discusses approaches to hydrodynamic modeling of fractured porous reservoirs. The purpose of the work is a comparative analysis of three models (EDFM, dual permeability, and single porosity) in terms of computational time, the possibility of adapting integral technological indicators, and the ability to reproduce spatial reserve depletion patterns. The study was performed on a synthetic test model with 25 fractures (aperture 3 mm, fracture permeability 100 D, matrix permeability 1 mD). The dual-permeability and single-porosity models were calibrated to the reference EDFM model by modifying the sigma factor, permeability, and endpoints of relative permeability curves. The flow-based upscaling method was used to upscale properties from the discrete fracture network (DFN) to the dual-medium model. It was found that the dual-permeability and single-porosity models are faster than EDFM in terms of computational time. Calibration of integral production indicators can be successfully accomplished for both simplified models. However, the spatial pattern of reserve depletion (maps of mobile oil reserves) differs for each approach. The results show that calibration based on integral indicators alone is insufficient for predicting reserve depletion patterns.

The paper presents a study on the influence of uncertainty in the initial data on geomechanical and strength properties of rock, as well as the horizontal reservoir stress, on the results of numerical estimation of the wellbore pressure required to prevent sand production. A model of the near-well rock mass is constructed from geophysical well logging data and laboratory core studies to solve this problem. The rock mass is considered a layered, multifacial, linear elastic medium. The hypothesis of subvertical principal stress was used for stress reconstruction. A method based on point measurements, specifically hydraulic fracturing data, is used to analyze horizontal stress profiles and reconstruct the stress distribution in a layered medium.

The uncertainty in the input data for the elastic and strength properties of the medium and the horizontal reservoir stresses is varied. These parameters are randomized within the range of uncertainty corresponding to the actual variation in the properties of rocks belonging to a specific geomechanical facies. The pressure allowing sand production is determined for various combinations of initial parameters using the Monte Carlo method within the framework of a simple model. The statistical approach makes it possible to determine the probability density function for sand production pressure with a given value of a certain parameter. Note that the prediction of the critical pressure is mostly sensitive to the magnitude of maximum horizontal stress.

The results of applying this approach allow us to accurately account for uncertainties in the initial data used to create geomechanical models. Using the example of the sand problem, we estimate the real ambiguity in determining the pressure at which irreversible rock destruction begins in the borehole surrounding rock masses during hydrocarbon deposit development.

This paper presents the results of modeling a centralizer-turbulator developed at the Department of oil and gas well drilling at Almetyevsk state technological university. The device was developed to address one of the key challenges in the construction of oil and gas wells with deviated and horizontal sections: reducing non-productive time associated with the elimination of complications and accidents during drilling.

During the centralizer design, drilling fluid flow modeling was performed for nine of the most common device profiles. The study revealed that the maximum flow velocity is achieved in the centralizer's central section. The use of modeling allows for the pre-determination of the necessary design and hydrodynamic characteristics of the device, which helps reduce development and prototyping costs.

The developed centralizer-turbulator generates an intense turbulent drilling fluid flow with high frequency and amplitude of local velocity pulsations. This flow regime prevents cuttings from settling on the wellbore walls and, consequently, reduces the likelihood of mechanical sticking. Reducing the number of such complications allows for a reduction in non-productive time during well construction and increases the economic efficiency of oilfield service companies.

This paper evaluates the dependence of the skin factor on various channel parameters in the application of controlled radial reservoir penetration, taking into account the available experience in optimizing wellbore treatment parameters based on the dynamics of changes in skin-factor values. The following variable parameters were considered: channel length, channel diameter, initial permeability of the producing formation, and the position of the channels relative to the top of the formation.

According to the results of hydrodynamic simulation, it was found that channel diameter directly affects the skin factor; however, for the cases considered, the skin factor values remain within a narrow range. At the same time, each subsequent increase in wellbore diameter produces a weaker effect in reducing the skin factor.

It has been determined that the technology of controlled radial reservoir stimulation yields a pronounced effect for reservoirs with permeability values up to 100 mD, while for reservoirs with permeability in the range of 100–200 mD, the effect is minimal. The placement of channels in the reservoir should be determined based on the geological and technical characteristics of the wellbore zone, as the change in the skin factor is negligible. It has been shown that the base channel model in controlled radial reservoir stimulation represents the optimal implementation option.

This paper presents the results of a comprehensive study of changes in the composition of residual bituminoids in core samples following various thermal treatment regimes. Oil-saturated core samples subjected to hot water, steam, superheated steam, and regimes with increased heat transfer fluid injection rates were used as test specimens. A suite of methods, including pyrolysis, SARA analysis and gas chromatography-mass spectrometry, was employed to assess changes in organic matter. It was established that all the exposure regimes studied lead to a reduction in the total hydrocarbon content of the core; however, the composition of the residual bituminoid varies depending on the initial properties of the oil. It has been shown that, for materials with a lighter and less transformed initial composition, the primary process is the selective removal of light and medium-molecular-weight components, resulting in the residual oil becoming heavier and enriched with resinous and asphaltene compounds. For samples with a higher-molecular-weight or biodegraded composition, the changes are significantly less pronounced, even under high-energy treatment conditions. A comprehensive interpretation of the results of pyrolysis, SARA analysis and gas chromatography-mass spectrometry has shown that identical thermal treatment regimes can lead to the formation of fundamentally different compositions of the residual bituminoid. The results obtained indicate the need to take into account the initial molecular-group composition of the oil when selecting thermal treatment regimes and predicting the properties of residual oil following thermal treatment of the reservoir.

To reduce anthropogenic carbon dioxide (CO₂) emissions, it is necessary to implement carbon capture projects followed by CO₂ injection into reservoir formations for geological storage and enhanced oil recovery. This paper examines the main CO₂ injection methods applied in reservoir systems for both enhanced oil recovery and long-term carbon sequestration. The analysis includes the injection of supercritical CO₂, water-alternating-gas (WAG) technology, and carbonated water injection. Several studies indicate that CO₂ retention is most efficient when it is injected in dissolved form within formation water compared to other methods; however, the total mass of CO₂ injected under such conditions is lower. In the supercritical state, a higher mobility of the displacement front is observed, leading to improved sweep efficiency. The WAG process demonstrates intermediate performance in terms of both sweep efficiency and oil displacement effectiveness.

This paper examines the results of determining the petromagnetic properties (magnetic susceptibility, thermomagnetic coefficient, and residual magnetization) of core material from a borehole located within the Navsky swell (West Siberian region). Stratigraphically, the core material consists of Jurassic sedimentary rocks and Paleozoic basement rocks. Paleozoic basement rocks are classified as having hard-to-recover reserves. The objective of this study is to obtain information on the petromagnetic properties of Jurassic and Paleozoic basement core material to assess the distribution of magnetic minerals and provide a detailed lithological subdivision of the studied deposits. It has been established that the following are readily identified in the Danilovskaya Formation: argillites by low values of magnetic susceptibility and residual magnetization; interlayers with elevated siderite concentrations by an increase in magnetic susceptibility and a decrease in the thermomagnetic coefficient. The petromagnetic properties of rocks of the Tyumen Formation can be used to: identify changes in lithological types in the section, namely, the change from the Danilovskaya Formation mudstones to the Tyumen Formation siltstones based on an increase in residual magnetization, as well as to identify layers with an increased siderite content based on an increase in magnetic susceptibility and a decrease in the thermomagnetic coefficient. The petromagnetic properties of Paleozoic basement rocks can be used for their detailed subdivision, namely: identifying weathering crust rocks based on magnetic susceptibility and thermomagnetic coefficient values; basalts based on magnetic susceptibility and residual magnetization; and effusive rocks of acidic composition based on magnetic susceptibility and residual magnetization.

The article presents the results of studying various features of clay-bearing rocks. The main properties of clay minerals that must be considered when selecting an optimal set of measures during the development of hard-to-recover reserves are determined.

It is recommended to apply a differentiated approach to the selection of displacing agents (displacement fluids) taking into account the prevailing clay minerals in the cement composition. This approach allows optimizing geological and technological processes and minimizing the risks of negative impact on the reservoir properties of the formation.

The article considers the possibility of using electrical conductivity as a potential method for assessing the corrosive activity of acid solutions. The main attention is paid to the analysis of the relationship between changes in the electrical conductivity of the acid medium and changes in its corrosive activity. In the experimental part, destabilization of the corrosion inhibitor was simulated by dosed introduction of iron ions into inhibited acid solutions. Gravimetric tests of carbon steel specimens and measurements of the specific electrical conductivity and ohmic resistance of the solutions were carried out in parallel. It was found that an increase in the concentration of iron ions in the solution leads to an increase in the corrosion rate of steel, accompanied by a decrease in electrical conductivity and an increase in ohmic resistance. The obtained data indicate a possible correlation between an increase in the corrosive activity of acid solutions and their electrical characteristics. Presumably, electrical conductivity measurement can be used as an additional auxiliary method for rapid monitoring of the state of acid solutions, for example, during their storage or before use. At the same time, electrical conductivity and ohmic resistance do not directly determine corrosive activity, but can potentially record transformations accompanying possible changes in acid solutions. Therefore, the proposed method can be considered as indicative, requiring further research.