At present, various advanced technologies for field development based on gas-enhanced oil recovery (EOR) methods are widely applied worldwide. These include high-pressure gas injection (hydrocarbon gases, nitrogen, flue gases), water-alternating-gas (WAG) injection, and carbon dioxide (CO₂) flooding. This study presents the results of filtration experiments investigating the application of gas EOR methods using core samples from a heavy oil reservoir. The primary objective of these experiments was to determine the oil displacement factor and analyze changes in interfacial tension upon injection of different gas agents. The following gases were utilized for modeling gas EOR processes: nitrogen (N₂), carbon dioxide (CO₂), and hydrocarbon gases (methane, propane). The core samples used in the study were obtained from the East Moldabek heavy oil field in Kazakhstan. Based on the results of the filtration experiments, carbon dioxide (CO₂) injection was identified as the most effective gas EOR method in terms of increasing the oil displacement factor, achieving an incremental displacement factor of 5.06%. Other gas injection methods demonstrated lower efficiency.

This paper examines the process of wormholes formation during hydrochloric acid treatment of well bottom-hole zone in carbonate formations. An algorithm for solving the problem of wormhole formation in a porous medium for a two-dimensional case was developed. Two-scale model (porescale and Darcy’s scale) taking into account convection, diffusion, and chemical reaction were used in this work in order to describe the dissolution of carbonates with hydrochloric acid (hydrochloric acid treatment). The initial distribution of the porosity field was generated as a distribution of random numbers around some mean value. Based on the distribution of the initial porosity field, the initial permeability field of the rock was calculated. The random distribution was used to describe the heterogeneity of the actual rock. The rest of the study parameters were taken from known experiments on the dissolution of carbonate cores. The numerical model was built for solving the system of equations for acid dissolution, and carbonate dissolution modes with hydrochloric acidwere obtained depending on the Damkohler number, Thiele modulus on the pore-scale and Darcy’s scale as a result of this research. Also, the optimal Damkohler numbers (injection rates) were found. The computer code for the problem of the development/growth of wormholes in a porous medium based on the developed algorithm was built using the C++ programming language.

One of the modern approaches for the effective development of small deposits is the construction and operation of wells with a complex architecture: horizontal wells (HW), sidetracks (BS, BGS), multilateral wells (MLW). Sidetracking makes it possible to reanimate an old well that is in an emergency state or inactivity for technological reasons, by opening layers that have not been previously developed, bypassing contamination zones, or watering the formation. This study examines the possibility of using horizontal sidetracks in the operating wells of the field of the Zhetybai group. To select the optimal length of the horizontal sidetrack of the wells, graphs of the dependences of the change in flow rate versus length of the horizontal well were built, taking into account the pressure losses due to friction. It can be seen from the dependence of NPV versus length of the horizontal wellbore that the maximum NPV is achieved with a horizontal wellbore length of 100 m. A further increase in the length of the horizontal wellbore leads to a decrease in NPV. This is due, firstly, to a decrease in oil prices, and secondly, interference of wells, a small number of residual reserves, and a small oil-bearing area. As a result of a comparison of technical and economic criteria, the optimal length of a horizontal wellbore is from 100-300 meters. Comparison of the flow rates of vertical wells and wells with horizontal sidetracks showed a clear advantage over the latter in all respects.

This article addresses the critical issue of low ultimate oil recovery in the development of highviscosity and heavy oil fields in Kazakhstan. The application of conventional waterflooding techniques at reservoirs such as Karazhanbas is often inefficient. The study substantiates the necessity of transitioning to chemical enhanced oil recovery (EOR) methods, which have been proven globally to increase the oil recovery factor (ORF). The research objective was a comparative evaluation of the efficiency of combined chemical EOR techniques -specifically, alkaline-surfactant (AS) and alkaline-surfactant-polymer (ASP) flooding - under high-viscosity oil conditions. The investigation was conducted using the Karazhanbas field as a case study. The target crude is characterized by a density of 0.935–0.945 g/cm³ and an insitu viscosity of 460-550 mPa·s at 30°C. Laboratory coreflood experiments were performed on reconstituted sandpack models, simulating reservoir rock, using a standard coreflood apparatus (UIK-S(2) setup). Tested formulations included alkalis (KOH, NaOH, NaHCO3), surfactants (sodium dodecyl sulfate, sodium dodecylbenzenesulfonate), and a polymer (partially hydrolyzed polyacrylamide, HPAM). The experimental results confirmed the potential for a substantial increase in the oil displacement efficiency through chemical injection. Following conventional waterflooding, which achieved a displacement coefficient in the range of 0.40-0.45, the injection of optimized chemical slugs provided an incremental recovery of 0.24 to 0.44 of the original oil in place. The most effective formulation was a three-component ASP system comprising 0.1 wt% NaOH, 0.023 wt% sodium dodecylbenzenesulfonate, and 0.05 wt% HPAM, delivering an incremental displacement coefficient of up to 0.437. The underlying mechanism is attributed to a synergistic effect: the alkali reacts with naphthenic acids in the crude to generate in-situ surfactants; the synthetic surfactant further reduces the oil-water interfacial tension to ultra-low values; and the polymer increases the aqueous phase viscosity, thereby improving mobility control, stabilizing the displacement front, and enhancing macroscopic sweep efficiency. The conducted research confirms the high potential of combined chemical EOR methods for improving the recovery of high-viscosity oils in Kazakhstan. This approach enables the production from poorly swept zones and can significantly increase the ultimate recovery factor in mature fields with challenging geological and physical properties.

This study provides a comprehensive systematization of global experience in the application of thermal enhanced oil recovery (EOR) methods, including in-situ combustion, hot water injection, and steam-based stimulation, with a particular focus on their applicability to high-viscosity oil reservoirs in Kazakhstan. The potential for implementing thermal EOR technologies in the development of high-viscosity oil fields in Kazakhstan is examined, where substantial reserves—estimated at 934 million tonnes— are concentrated in the western regions of the country. The analysis covers the applicability of in-situ combustion, hot water injection, and steam stimulation to the geological and physical conditions of the Karazhanbas, North Buzachi, Kalamkas, Kenkiyak, and East Moldabek fields. Special emphasis is placed on the results of laboratory core flooding experiments conducted on samples from the East Moldabek site. The experiments were performed under conditions simulating reservoir temperature and pressure, employing stepwise heating of the displacing fluid. This approach enabled a quantitative assessment of the influence of temperature and initial oil viscosity on the incremental oil recovery factor (ORF). For cores with oil viscosity of 116 mPa·s, thermal stimulation following conventional waterflooding resulted in an additional ORF increase of 8.75%; for 96 mPa·s — 2.92%; and for 21 mPa·s – 1.26%. The maximum recorded incremental ORF in individual tests reached 8.57%. Sample pore volumes ranged from 6.28 to 7.04 cm³, porosity from 28.92% to 32.6%, and absolute permeability from 259.8 to 1000 mD. The results demonstrate that thermal stimulation yields the highest incremental recovery in high-viscosity reservoirs, whereas for low-viscosity oils the improvement does not exceed 3%. The findings support the feasibility of thermal EOR deployment in Kazakhstan and highlight the need for scaling up pilot projects and conducting field trials, with due consideration of the physico-chemical properties of crude oil and reservoir petrophysical characteristics.