Gas Condensate Reservoirs Research Articles

Numerical Well Test Analysis of Condensate Dropout Effects in Dual-Permeability Model of Naturally Fractured Gas Condensate Reservoirs: Case Studies in the South of Iran

Naturally fractured reservoirs (NFR) represent an important percentage of worldwide hydrocarbon reserves and production. The performance of naturally fractured gas condensate reservoirs would be more complicated regarding both rock and fluid effects. In contrast to the dual-porosity model, dual-porosity/dual-permeability (dual-permeability) model is considered as a modified model, in which flow to the wellbore occurs through both matrix and fracture systems. Fluid flow in gas condensate reservoirs usually demonstrates intricate flow behavior when the flowing bottom-hole pressure falls below the dew point. Accordingly, different regions with different characteristics are formed within the reservoir. These regions can be recognized by pressure transient analysis. Consequently, distinguishing between reservoir effects and fluid effects is challenging in these specific reservoirs and needs numerical simulation. The main objective of this paper is to examine the effect of condensate banking on the pressure behavior of lean and rich gas condensate NFRs through a simulation approach. Subsequently, evaluation of early-time characteristics of the pressure transient data is provided through a single well compositional simulation model. Then, drawdown, buildup, and multirate tests are conducted to establish the condition in which the flowing bottom-hole pressure drops below the dew point causing retrograde condensation. The simulation results are confirmed through well test analysis in both Iranian naturally fractured rich and lean gas condensate fields. Interpretations of simulation analysis revealed that the richer gas is more prone to condensation. When the pressure drops below the dew point, the pressure derivative curves in the rich gas system encounter a more shift to the right, and the trough becomes more pronounced as compared to the lean one.

The influence of fluorochemical-modified graphene oxide on the gas-wetting alteration of reservoir cores

Gas condensate reservoir plays an indispensable role in the supply of fossil fuels to alleviate energy shortages. However, liquid condensate near the wellbore can lead to a decrease in gas well deliverability during development. In this work, the strong gas-wetting graphene oxide is prepared by functional modification and characterized by FTIR and XPS. Thermodynamic analysis shows that surface modification can improve the temperature resistance of graphene oxide. To investigate the influence of gas-wetting alteration on the core, the contact angle of the droplets on the core surface is measured and the results exhibit that the contact angles of water and n-hexadecane increase from 23° and 0–140° and 132°, respectively. Meanwhile, the surface free energy is sharply reduced from 67.97 mN/m to 1.15 mN/m after treatment. These results are further verified by imbibition. Core flooding illustrates that the required pressure for water and n-hexadecane injection into the core is reduced by 57.06% and 54.08%, respectively, and the permeability of different cores is improved after the gas-wetting alteration. Also, the analyses of the 3D morphology and elements demonstrate that the gas-wetting adsorption layer has been formed on the core surface. These results indicate that the liquid is easier to peel from the core surface to improve the ability of transportation and distribution. Besides, this work also reveals the mechanism of gas-wetting alteration so that it can be better applied to other oil fields and engineering fields.

Predicting the condensate viscosity near the wellbore by ELM and ANFIS-PSO strategies

By lowering the pressure beneath the dew point as the result of production in gas condensate (GC) reservoirs, liquid droplets are formed in the borehole zone. Accurate calculation of pressure decline and optimization operations in these reservoirs need to know and predict the specific properties such as liquid viscosity. Empirical models have already been developed to predict this parameter. Due to the peculiar behavior of fluids beneath the dew point pressure (DPP), the prediction of liquid viscosity associates with an error. With the development of machine learning (ML) approaches, studies on fluid properties like other sciences have entered a new phase. In this study, extreme learning machine (ELM) and adaptive neuro-fuzzy inference system with particle swarm optimization (ANFIS-PSO) methods applied to this end. Therefore, a large data bank of reservoir and fluid properties including reservoir temperature and pressure, specific gravity (SG) of gas, API gravity, and gas to oil ratio (Rs) were used. The results showed that R-squared and RMSE for ANFIS-PSO are 0.762 and 0.15, respectively, while these values are 0.941 and 0.06 for ELM which shows that the last model has a better performance in estimating output values. Also, the range of reliable data is determined, and further, a sensitivity analysis was done, which showed that the greatest impact on the viscosity was from SG, and API gravity has the least effect on it. This model can be used as a reference for calculating condensate viscosity and also by expanding the range of datasets, it can be applied in the commercial software.

Novel Microfluidic Device for Dew Point Pressure Measurement of Retrograde Gas Condensates

Accumulation of liquid dropout in gas condensate reservoirs occurs when the pressure falls below the dew point and leads to declining well productivity. We have developed a microfluidic device to a...

Change of phase state during multi-cycle injection and production process of condensate gas reservoir based underground gas storage

Based on the differences in production mode and operation process between gas storage and gas reservoir, we established a phase balance test procedure and a theoretical simulation model of phase balance during multi-cycles of injection and production of underground gas storage (UGS) rebuilt from condensate gas reservoir to study the phase characteristics of produced and remaining fluids during multi-cycles of injection and production. Take condensate reservoir gas storage as example, the composition of produced fluid and remaining fluid, phase state of remaining fluid, retrograde condensate saturation and condensate recovery degree in the process of multi-cycles of injection-production were studied through multi-cycle injection-production experiment and phase equilibrium theory simulation. The injected gas could greatly improve the recovery of condensate oil in the gas reservoir, and the condensate oil recovery increased by 42% after 5 cycles of injection and production; the injected gas had significant evaporative and extraction effects on the condensate, especially during the first two cycles; the condensate oil saturation of the formation decreased with the increase of injection-production cycles, and the condensate oil saturation after multi-cycles of injection-production was almost 0; the storage capacity increased by about 7.5% after multi-cycles of injection and production, and the cumulative gas injection volume in the 5th cycle increased by about 25% compared with that in the 1st cycle.

Fluoro-chemical foam injection for wettability alteration of sandstone and carbonate reservoirs rocks towards gas-wet state

In gas condensate reservoirs, when fluid pressure decreases below its dew point pressure, it contributes to condensate build-up around the wellbore. Due to liquid condensation, gas and condensate relative permeability and mobility significantly drop and well productivity is considerably decreased. Several approaches have been recommended to mitigate condensate banking. Wettability alteration of the reservoir rock surface towards gas-wet is considered as one of the promising techniques for alleviating condensate banking. In this communication, a fluoro-chemical foam treatment technique is introduced to alleviate the condensate banking. To evaluate the effectiveness of the foam injection technique for the gas-wetting alteration of sandstone and carbonate cores, the contact angle measurement, liquid imbibition, and core displacement tests were conducted in the gas-liquid-core system. The adsorption of the fluoro-chemical solution on sandstone and carbonate samples was verified by surface analysis techniques including SEM, FTIR, and EDXS. The results show that the contact angles of brine and hexadecane droplets on the treated sandstone substrate increased from 0° and 0° to to135° and 103°, respectively. Moreover, treatment of carbonate substrate with fluoro-chemical solution resulted in an increase of 0° to 130° and 0° to 123° for brine and hexadecane contact angles, respectively. After treatment, the imbibition of brine and hexadecane liquids into the cores decreased significantly. Finally, the results of dynamic two-phase core flooding in sandstone and carbonate cores show that the chemical foam treatment can improve the end-point gas relative permeabilities by the factors of 1.704 and 1.69 for sandstone and carbonate cores, respectively.

Design of fluorine-modified nanocrystalline cellulose achieving super gas-wetting alteration of reservoir cores

In gas condensate reservoirs, liquid condensation near the wellbore region can break gas well deliverability when the pressure drops lower than dew point. Gas-wetting alteration is one of the potential approaches to overcome the difficulty. However, gas production remains restricted because the wettability of the core surface can only be altered from original liquid-wetting to neutral gas-wetting by traditional methods. Herein, fluorine-modified nanocrystalline cellulose is developed to achieve super gas-wetting alteration, increasing the contact angles of brine and decane on core surface from 22° and 0o to 153° and 142°, respectively. This product not only reduces the surface free energy from 68.41 mN/m to 0.35 mN/m but also increases the surface roughness from 68.23 nm to 154.51 nm. The capillary tube and imbibition experiments further confirm that the wettability of the core surface has been altered from strong liquid-wetting to super gas-wetting. This result indicates that the liquid is easier to peel from the core surface to improve the ability of transportation and distribution. Besides, after the super gas-wetting alteration, the required pressure for displacement is reduced and the core permeability is restored dramatically. Meanwhile, it has been proved that fluorine-modified cellulose is more suitable for unconventional low permeability reservoirs. This work also reveals the mechanism of super gas-wetting alteration in detail, which will expand the better application of the material in more oilfields and other mining engineering developments.

Achieving the Super Gas-Wetting Alteration by Functionalized Nano-Silica for Improving Fluid Flowing Capacity in Gas Condensate Reservoirs

It is well-known that the production of gas-condensate reservoirs is significantly affected by the liquid condensation near the wellbore region. Gas-wetting alteration can be one of the most effective approaches to alleviate condensate accumulation and improve liquid distribution. However, gas well deliverability is still limited because the wettability of cores is altered only from liquid-wetting to intermediate gas-wetting by using traditional chemical stimulation. To solve this bottleneck problem, herein, we developed a fluorine-functionalized nanosilica to achieve super gas-wetting alteration, increasing the contact angles of water and n-hexadecane on the treated core surface from 23 and 0° to 157 and 145°, respectively. The surface free energy reduces rapidly from 67.97 to 0.23 mN/m. The super gas-wetting adsorption layer on the core surface formed by functionalized nanosilica not only increases the surface roughness but also reduces the surface free energy. The core flooding confirms that the required pressure for displacement is apparently reduced. Meanwhile, the core permeability can be dramatically restored after the super gas-wetting alteration. The microscopic visualization is employed to further understand the impact of fluorine-functionalized nanosilica on the fluid flow behavior and mechanism in porous media. The oil saturation in the micromodel decreases sharply from 48.75 to 7.84%, eliminating the "water locking effect" and "Jiamin effect", which indicates that the added functional nanosilica effectively improves fluid flow capacity and may contribute to production in the gas condensate reservoirs. In addition, this work reveals the fluid flow behavior and mechanism in the reservoir in detail, which will expand the better application of this material to many oilfields and other mining engineering systems.

Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

Positive coupling effect in gas condensate flow: Role of capillary number, Scheludko number and Weber number

The coupled flow in gas condensate reservoirs is investigated using a purely theoretical approach for the description of velocity effect on relative permeability in the absence of inertial effects. A combination of linear stability analysis and dynamic wetting theory is used to describe this coupled flow under the effect of viscous resistance and disjoining pressure. The role of capillary number and Scheludko number (i.e. the dimensionless ratio of disjoining pressure to capillary pressure) is clearly expressed through closed relative permeability formula for the limits of negligible and strong disjoining effect. The model predicts no velocity dependence at very low capillary numbers and a positive velocity effect at high capillary numbers but the negative velocity effect at very high velocities due to strong inertial effects is not predicted due to the model's basic assumptions. Although the model was not intended to serve as a substitute for the experiment, reasonable quantitative agreement is observed between its predictions and available experimental data as long as the Weber number (the dimensionless ratio of inertial resistance to capillary pressure) is smaller than 5 × 10−5, with an average and a maximum relative deviation of 16% and 67% respectively, for a total number of 49 data points.

Development of production data analysis models for multi-well gas condensate reservoirs

Production data Analysis (PDA) is a crucial step to determine the recoverable reserve and predict the future performance of the reservoir. Moreover, using these data for a long period which covers transient and pseudo steady state conditions, will result to a great insight of reservoir behavior. One of the challenges of gas condensate reservoirs is well-deliverability determination. All techniques and models for evaluation of reservoir performance assume the constant well drainage area and single well production. The drainage area of the wells in a multi-well reservoir is affected by the interference effect of the wells. Hence, the prediction of well performance by conventional models, assuming constant well drainage area is not applicable in this case. An overall outline of this study is to propose an analytic technique to distinguish the well performance in a multi-well system in gas condensate reservoirs. Moreover, theoretic perception of pseudo steady state models and dynamic material balance for developed model is presented.With the intension of ascertaining the accuracy of proposed methodology, result of this approach is compared with commercial compositional simulator. The results ensure the accuracy of its application in multi-well gas condensate reservoirs.

Pore-scale compositional modeling of gas-condensate flow: Effects of interfacial tension and flow velocity on relative permeability

Liquid dropout and retention in gas-condensate reservoirs, specially in the near wellbore region, obstruct gas flowing paths and impact negatively the produced fluid volume and composition. Yet, condensate banking forecasting is commonly inaccurate, as experiments seldom reproduce reservoir extreme conditions and complex fluid composition, while most pore-scale models oversimplify the physics of phase transitions between gas and condensate. To address this gap, a fully implicit isothermal compositional pore-network model for gas and condensate flow is presented. The proposed pore-networks consist of 3D structures of pores connected by constricted circular capillaries. Hydraulic conductances are calculated for the capillaries, which can exhibit single-phase flow or two-phase annular flow, according to local gas and liquid saturations, or be blocked by a liquid bridge, when capillary forces overcome viscous forces. A PT-flash based on the Peng-Robinson EoS is performed at control volumes defined for the pores at each time step, updating the phases properties. Flow analyses were carried based on coreflooding experiments reported in the literature, with matching fluid composition and flow conditions, and approximated pore-space geometry. Predicted and measured relative permeability curves showed good quantitative agreement, for two values of interfacial tension and three values of gas flow velocity.

The influence of nitrogen injection duration at the initial gas-water contact on the gas recovery factor

This paper reports a study that employed a digital three-dimensional model of the gas condensate reservoir to investigate the process of nitrogen injection at the boundary of initial gas-water contact at different values of the injection duration. The calculations were performed for 5, 6, 8, 10, 12 and 14 months injection duration. Based on the modeling results, it was found that increasing the duration of the nitrogen injection decreases the operation time of production wells until the breakthrough of non-hydrocarbon gas. Based on the analysis of the technological indicators of reservoir development, it was established that the introduction of technology of the nitrogen injection into a reservoir ensures a reduction in the volume of reservoir water production. The cumulative water production at the time of nitrogen breakthrough to the production wells at the nitrogen injection duration of 5 months is 197,3 thousand m3; of 14 months – 0,038 m3. According to the results from the statistical treatment of estimation data, the optimal value for the nitrogen injection duration was determined, which is 8,04 months. The ultimate gas recovery factor for the optimal period of the non-hydrocarbon gas injection is 58,11 %, and in the development of a productive reservoir for depletion – 34,6 %. Based on the research results, the technological efficiency of nitrogen injection into a productive reservoir has been determined at the boundary of initial gas-water contact in order to slow the movement of reservoir water into gas-saturated horizons. This study results allow the improvement of the existing technologies of hydrocarbon fields development under conditions of water drive. The use of the results of the research carried out in production will make it possible to reduce the volume of cumulative water production and increase the ultimate gas recovery factors to 23,51 %

Dik ve Yatay Kuyuların Tight Gaz Kondensat Rezervuarında Kuru Gaz Enjeksiyonlu ve Enjeksiyonsuz Üretim Performanslarının Karşılaştırılması

In this study, the comparison of dry gas injection for vertical and horizontal production well scenarios are investigated by means of conducting a reservoir simulation study for a tight condensate gas reservoir. In order to conduct this study a reservoir pattern has been defined. The selected reservoir pattern is 420x420 m in areal extend and 50 m in thickness. All of the necessary reservoir rock properties, and fluid specifications together with reservoir fluid compositions have been determined considering the data available in the literature. A professional reservoir simulation computer program has been utilized for the realization of this study. The well directional trajectories are determined through a dedicated drilling and completion study. The study proved that horizontal wells are much effective in drainage mechanisms in comparison to vertical wells by the fact that dry gas being able to efficiently reach to horizontal drain sections to prevent condensation of oil in the formation for gas condensate reservoirs. The literature contains research on influence of horizontal well on the retardation of the oil condensation inside the gas condensate reservoirs. This research study is conducted to fill the gap in literature in relation to comparison of the well performance of the vertical and horizontal wells during the dry gas injection.

Maximizing the Benefit of Rate Transient Analysis for Gas Condensate Reservoirs

In recent years, many trials have been made to use the Rate Transient Analysis (RTA) techniques as a method to describe the gas condensate reservoirs. The problem with using these techniques is the multi-phase behavior of the gas condensate reservoirs. Therefore, the Pressure Transient Analysis (PTA) is commonly used in this case to analyze the reservoir parameters. In this paper, we are going to compare the results of both PTA and RTA of three wells in gas condensate reservoirs. The comparison showed a great match between the results of the two mentioned techniques for the first time using a reference GOR of 75,000 SCF/STB. Therefore, we concluded that we could depend on RTA instead of PTA to spare the cost associated with the PTA in the gas condensate reservoirs.

Investigation of the efficiency of gas condensate reservoirs waterflooding at different stages of development

The study of flooding gas condensate reservoirs at different stages of depletion (25, 50, 75% of the dew point pressure and at the maximum condensation pressure) with different potential hydrocarbon content of 100, 300 and 500 g/m3 and different voidage replacement by using injection (50, 100 and 150%). The results showed a positive effect of water injection on the increase of the condensate recovery factor, but a decrease in gas production compared to the basic options of development at depletion drive. Thus, for formation systems with medium and high potential yield of liquid hydrocarbons C5+, the largest incremental production is obtained in the case when water injection begins with minimum depletion of formation energy. While for a formation system with a low potential yield (100 g/m3) the maximum technological effect is obtained under the condition of maximum depletion. In the case of medium and high C5+ yield in the formation gas, with a slight decrease in the formation pressure by 25 or 50% of the dew point pressure, the maximum increase in the condensate recovery factor is achieved at high injection rates with 100 or 150% voidage replacement. The obtained results can be used for rapid screening of potential methods of impact on the gas condensate reservoir, and the final decision concerning the technological parameters of production and injection wells operation will be made due to the results of optimization of multivariate hydrodynamic calculations using geological and technological models.

Wspomaganie wydobycia gazu ziemnego i kondensatu: przegląd opublikowanych projektów pilotażowych i komercyjnych

The majority of the Ukrainian gas condensate fields are in the final stage of development. The high level of reservoir energy depletion has caused significant in situ losses of condensed hydrocarbons. Improving and increasing hydrocarbon production is of great importance to the energy independence of Ukraine. In this paper, a review of the pilot and commercial enhanced gas and condensate recovery (EGR) projects was performed, based on published papers and literature sources, in order to identify those projects which could potentially be applied to the reservoir conditions of Ukrainian gas condensate fields. The EGR methods included the injection of dry gas (methane), hydrocarbon solvents (gas enriched with C2–C4 components), or nitrogen and carbon dioxide. The most commonly used and proven method is dry gas injection, which can be applied at any stage of the field’s development. Dry gas and intra-well cycling was done on five Ukrainian reservoirs, but because of the need to block significant volumes of sales gas they are not being considered for commercial application. Nitrogen has a number of significant advantages, but the fact that it increases the dew point pressure makes it applicable only at the early stage, when the reservoir pressure is above or near the dew point. Carbon dioxide is actively used for enhanced oil recovery (EOR) or for geological storage in depleted gas reservoirs. In light of the growing need to reduce carbon footprints, CO2 capture and sequestration is becoming very favourable, especially due to the low multi-contact miscibility pressure, the high density under reservoir conditions, and the good miscibility with formation water. All of these factors make it a good candidate for depleted gas condensate reservoirs.

Numerical Simulation Considering Non-Equilibrium Phase Change Volatile Oil Reservoir: A Case Study of Wenchang 8-3 Oil Reservoir

As a typical volatile oil reservoir, the actual production characteristics of Wenchang 8-3 reservoir are inconsistent with the results of traditional phase equilibrium experiments. The conventional isothermal instantaneous phase equilibrium theory cannot meet the production performance or numerical simulation analysis requirements of this type of reservoir. The thermodynamic properties of volatile oil reservoirs are like those of condensate gas reservoirs. As the formation pressure drops below the dew point pressure during the mining process, the balance between the liquid phase and the gas phase is not completed instantaneously. Based on the non-equilibrium phase recovery treatment method of the condensate gas reservoir, the phase behavior change curve of the A4h well of Wenchang 8-3 oil reservoir recovered from the saturation pressure to three different pressures is analyzed. The accuracy of the numerical simulation results with or without non-equilibrium phase transition is compared. The results show that the non-equilibrium phase change has a great impact on the production performance of volatile oil reservoirs; the numerical simulation results considering the non-equilibrium phase transition are in good agreement with the actual production performance of a single well and can better reflect the actual situation of this type of reservoir. Therefore, considering the effects of non-equilibrium phase transitions has important guiding significance for the dynamic analysis of volatile oil reservoirs, numerical simulation, and the formulation of development management strategies.

Studying the influence of the carbon dioxide injection period duration on the gas recovery factor during the gas condensate fields development under water drive

Purpose. Studying the process of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors. Methods. To assess the influence on gas recovery factor of the duration of carbon dioxide injection period at the initial gas-water contact, a reservoir development is studied using the main Eclipse and Petrel hydrodynamic modeling tools of the Schlumberger company on the example of a hypothetical three-dimensional model of a gas-condensate reservoir. Findings. The dependence of the main technological indicators of reservoir development on the duration of the carbon dioxide injection period at the initial gas-water contact has been determined. It has been revealed that an increase in the duration of the non-hydrocarbon gas injection period leads to a decrease in the formation water cumulative production. It has been found that when injecting carbon dioxide, an artificial barrier is created due to which the formation water inflow into the gas-saturated intervals of the productive horizon is partially blocked. The final gas recovery factor when injecting carbon dioxide is 61.98%, and when developing the reservoir for depletion – 48.04%. The results of the research performed indicate the technological efficiency of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors for the conditions of a particular field. Originality. The optimal value of duration of the carbon dioxide injection period at the initial gas-water contact has been determined, which is 16.32 months based on the statistical processing of calculated data for the conditions of a particular field. Practical implications. The use of the results makes it possible to improve the existing technologies for the gas condensate fields development under water drive and to increase the final hydrocarbon recovery factor.

Approval of the technology of carbon dioxide injection into the V-16 water driven reservoir of the Hadiach field (Ukraine) under the conditions of the water pressure mode pages 1–2

The object of research is water-driven gas-condensate reservoirs. Using the main hydrodynamic modeling tools Eclipse and Petrel from Schlumberger (USA), the study was carried out to improve the existing technologies for the displacement of residual gas reserves by carbon dioxide from the water-driven gas-condensate reservoirs. The carbon dioxide injection technology was tested in the V-16 reservoir of the Hadiach oil and gas condensate field (Ukraine). According to the study results, it was found that due to the injection of non-hydrocarbon gas, the cumulative water production are reduced compared to the depletion. Based on the obtained modeling results, the calculation of the predicted hydrocarbon recovery factors at the moment of carbon dioxide breakthrough into the production well was carried out according to the cumulative formation water production. According to the calculations, it was found that the implementation of the enhanced gas recovery technology provides significantly higher ultimate hydrocarbon recovery compared to the depletion. The predicted gas recovery factor when injecting carbon dioxide into the V-16 reservoir increases by 2.95 % of the residual gas reserves, and the condensate recovery factor for these conditions by 1.24 %. Based on the study results, the technological efficiency of using carbon dioxide as an injection agent to increase the hydrocarbon recovery from water-driven reservoirs was established. According to the simulation results, the implementation of the technology of carbon dioxide injection into the V-16 reservoir of the Hadiach oil and gas condensate field can significantly increase the hydrocarbon recovery from the deposit, thereby increasing the production capacity of the field.