Petroleum and natural gas are among the most critical energy sources in contemporary societies, still impossible to replace with recoverable resources. They are projected to play a pivotal role in addressing the global energy demands in the near future. Achieving energy security for the present turbulent times is of utmost importance. The discovery and development of new hydrocarbon deposits, along with increasing productivity from existing fields. The majority of onshore oil and gas fields in Bulgaria are in a mature to final stage of exploitation, thus emphasizing the need for innovative approaches and modern methods for outlining perspective exploration territories. Some of the economic oil fields are still in production (Tyulenovo, Dolni and Gorni Dabnik, Dolni Lukovit - Staroseltsi and Burdarski Geran) and their recoverable potential remains to be fully tapped. Conversely, a number of other fields have been classified as depleted or with minimal remaining reserves, which seriously raises the question of their future (e.g., Devetaki, Pisarovo, Aglen and Deventsi). These "depleted" deposits are of significant interest due to the possibilities to reassess and apply modern technologies for optimization and increasing the yield from already exhausted fields. Therefore, the primary goals are enhancing the recovery factor to prolong the operational lifespan of existing brownfields and reassessing the hydrocarbon perspective areas in Northern Bulgaria. Moreover, a significant set of geological, geophysical and technical data concerning hydrocarbon accumulations is available for reassessment. This extensive data base provides a robust foundation for contemporary characterization and evaluation of natural reservoirs in the case of Devetaki gas condensate field and overall evaluation of several perspective adjacent areas (Bohot, Gradina, Kriva Bara, Bazovets, Tarnak and etc.). It also facilitates quantitative estimations of resource and reserve volumes within these reservoirs as well as delineation of future exploration territories. The integration of software platforms with modern geoscience concepts offers a cost-effective tool for economic growth. This study highlights the need for realistic geological models and production plans to enhance recovery from mature oil and gas fields in Bulgaria. Reassessment of the promising areas where hydrocarbons are present will also provide a new in-depth view on the future oil and gas sustainable exploration.

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.

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 BT 6 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 (C 5 +) system. Also, the authors found that the formation of complexes with C 5 + 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.

This paper addresses the pressing issue of declining productivity in gas-condensate fields with low reservoir filtration-capacity properties, using the Zharkum field (Kazakhstan) as a case study. The authors consider the application of hydraulic fracturing (HF) as a key method of production stimulation under such conditions. The article substantiates the necessity of HF to optimize well flow rates and increase the hydrocarbon recovery factor. An analysis of reservoir pressure dynamics and gas production at the field from 2018 to 2022 revealed an overall decline in reservoir energy. The results of gasdynamic studies confirmed low reservoir permeability with predominantly clean near-wellbore zones, indicating natural geological constraints. Based on the conducted studies, conclusions were drawn regarding the high efficiency of previous HF operations at wells No. 6 and No. 8, where gas flow rates increased more than fivefold, and the positive effect lasted up to 485 days. The results of fracture geometry studies confirmed their effectiveness. The article also justifies the choice of Fores ForeProp 30/50 proppant, which demonstrated high conductivity under high closure pressures. A comparison of actual and projected performance indicators revealed underproduction in previous years; however, in 2022, a positive trend was observed. Based on the research conducted, recommendations were formulated for the further implementation of the HF program in 2025–2026 to stabilize and increase production under reservoir depletion conditions.

The Karachaganak field (Karachaganak oil and gas condensate field) is characterized by "acidic" production conditions: the presence of both CO₂ and H₂S with relatively low water availability, complex stratigraphy of the deposit and an extremely continental climate. The complex corrosion hazard is determined by a combination of mechanisms: carbon dioxide corrosion of steel, sulfide stress cracking and hydrogen embrittlement in environments with HS, hydrogen-induced corrosion/delamination, acidification of condensation water, as well as microbiological corrosion. The article provides an analytical review of corrosion factors for a typical well stock and pipeline strapping in Karachaganak; a research methodology with simulated reservoir/surface conditions is proposed; the results of a computational and experimental assessment of metal loss rates and the risk of brittle fracture forms for API steels and corrosion-resistant alloys according to ISO 15156 are discussed; a set of engineering solutions is formed: selection of materials, inhibitory protection, pH stabilization, moisture/salt management, pipe cleaning, monitoring (ER/LPR samples, coupons, inspection). It has been shown that at partial pressures of co₂≈H₂S and temperatures of 70-95 °C, FECO₃ protective films are destabilized by hydrogen sulfide phases (mackinawite, greigite), which increases the localization of corrosion and sensitivity to SSC; at the same time, low waterlogging and effective degassing/drying of gas reduce the risks in the main lines of dry gas. The findings confirm the need for differentiated corrosion management by systems (borehole—fountain fittings—plume—separation—water separation—reinjection), as well as the integration of the RBI approach into the maintenance program.

Currently, the problem of reducing the efficiency of reservoir pressure maintenance systems at late stages of field development with highly heterogeneous reservoirs is a serious one for the oil and gas industry. This paper considers the Srednebotuobinskoye oil and gas condensate field (SBNGKM), which is characterized by highly heterogeneous reservoir, water cut in some wells exceeding 95%, and low water injection efficiency. In this paper, waterflooding optimization using the streamline method was applied for the first time for the conditions of one of the largest fields in Yakutia – SBNGKM. The objective of the work was to increase the efficiency of reservoir pressure maintenance by redistributing injection between injection wells using hydrodynamic modeling of streamlines. The research materials included a three-dimensional hydrodynamic model of the Bt formation of the SBNGKM central block in the tNavigator software, historical data on 37 production and 15 injection wells for the period 2010-2021. An algorithm for redistributing injection with an increase in volumes in highly efficient wells by 20-30% and a decrease in low-efficiency wells by 15–40% was implemented. The results showed an increase in average injection efficiency by 41%, a decrease in water cut by 3.2% and an increase in cumulative oil production by 65,414 tons over a 10-year forecast period. Practical significance is confirmed by an increased ultimate oil recovery factor by 1.7% without capital expenditures. The prospects of the study are associated with the development of adaptive algorithms for automatic optimization based on machine learning and the integration of real monitoring systems for filtration parameters. The implementation of the proposed methodology can significantly increase the economic efficiency of developing complex reservoirs at a late stage of operation due to the rational use of the existing well infrastructure and water resources.

During the long-term development of gas and gas condensate fields, the operating modes of production and gathering systems change significantly. At the same time, existing equipment cannot always provide safe and optimal operating modes due to technological limitations. Existing equipment needs to be rebuilt to prevent unwanted production and gathering systems. The purpose of the work is to develop approaches that allow the optimal configuration of preventive measures (construction of parallel pipelines, loopings, jumpers, regulation of well and compressor station operating modes), which will ensure the safe and efficient operation of the field. The article discusses two approaches used in the selection of management measures, taking into account the effective regulation of fishing regimes. Using the described approaches, such a configuration of measures has been selected that allows maintaining the planned production levels and operating the fishery in a safe mode. The approaches considered in the study were used to assess the need for looping during the operation of the gas condensate field. The calculations showed the effectiveness of the proposed approaches and the possibility of using them for the operational assessment of management activities.

logical and geophysical data from the Kuanish gas-condensate field, discovered in 1969 and located within the North Ustyurt Syneclise in the Republic of Karakalpakstan (Uzbekistan). Kuanish became the first field in the Ustyurt region where hydrocarbon accumulations of confirmed commercial significance were discovered in Lower Jurassic deposits. The reserves estimation conducted in 1974 failed to address all questions regarding the geological structure of the field. As a result, the hydrocarbon resource assessment was carried out with a degree of caution, leaving potential opportunities for revisiting the entire set of geological and geophysical data and increasing the reserves of gas and condensate. The aim of the study was to refine the structure of the productive part of the field and identify additional exploration prospects within the framework of rational subsoil use. Based on a detailed reinterpretation of previously acquired 2D seismic data (CDP method) and information from deep exploration wells, a correction to the structural framework was made. As a result of the analysis, the position of the gas-water contact (GWC) was refined, and the geometry of the accumulations was updated considering new insights into trap structures and fluid saturation characteristics. Particular attention was given to sections of the accumulation that had previously been excluded from prospectivity assessments. Taking into account the reinterpretation of the existing geological and geophysical data, a revised geological model of the hydrocarbon accumulation was developed, which allowed for the identification of additional potential hydrocarbon volumes. The recalculated recoverable reserves of gas and gas condensate demonstrated a significant increase compared to previous estimates. The study also substantiates the need to drill two additional appraisal wells to verify and refine the deep geological structure of the accumulation as presented in the authors’ model, confirm reservoir parameters, and update the hydrocarbon reserves assessment with the goal of bringing them into development. The results obtained highlight the high potential for further development of the field, enhance the efficiency of exploration planning, and provide a basis for updating project documentation in line with the new data.

The southern margin block of the Xinjiang Oilfield represents a typical ultra-high-pressure condensate gas field. Existing surface throttling practices rely heavily on empirical experience, with the underlying throttling mechanisms remaining unclear and lacking systematic theoretical support. In this study, the TW1 Well is selected as the research subject. Based on the principle of equal total enthalpy before and after throttling—and with particular attention to the effects of condensate gas heavy components and water on enthalpy calculations—a mathematical model for throttling-induced temperature drop, tailored to ultra-high-pressure condensate gas, is developed. The model enables a systematic analysis of temperature variations throughout the throttling process. Results indicate that the pre-throttle temperature is the primary factor controlling the magnitude of temperature change, and that post-throttle temperature rise may occur due to the Joule–Thomson coefficient becoming negative under ultra-high-pressure conditions. By integrating hydrate-formation prediction with differential pressure calculations across the throttling valve, a rational production scheme is proposed. This study provides a theoretical basis for understanding the mechanisms of ultra-high-pressure condensate gas well throttling and delivers critical technical support for the scientific design and optimization of surface throttling operations.

In the article, temperature and condensation distribution reports were made during the process of periodic injection of liquid hydrocarbons with a temperature greater than the formation temperature into the wellbore zone in gas condensate wells. Propane gas, a liquid hydrocarbon, was used as a solvent. The process of influencing the well-surrounding zone with hot gases occurs under conditions of multi-contact compression of the gas-condensate mixture with propane and propane mixed with dry gases. As a result, in the heated zone, propane completely vaporizes the formation water, while a portion is vaporized and compressed with gas. The removal of retrograde condensate by first injecting hot propane-butane fractions and then hot gases is considered an effective and feasible approach to increasing gas condensate well productivity. This method enhances hydrocarbon recovery by preventing condensate accumulation, which can hinder gas flow. It significantly reduces the required volume of dry gas injection, thereby improving the overall efficiency of the process. By influencing the wellbore zone with hot gases, it is possible to optimize resource consumption while maintaining high productivity. Compared to isothermal injection, the proposed method allows for a 2.5–3 times reduction in the volume of working agents while achieving similar production levels. This approach not only enhances economic feasibility but also minimizes operational costs and environmental impact, making it a promising technique for gas condensate field development. Overall, the findings suggest that controlled thermal injection can serve as an efficient strategy for maintaining and even enhancing gas production rates over extended periods, ensuring the sustainable development of gas condensate fields.

The article presents the results of the lithofacies study of the Late Vendian Botuobinsky horizon of the southeastern part of the Srednebotuobinskoye field. The main problem solved in the article is the search for intervals with the best reservoir properties within the Botuobinsky horizon and the forecast of their distribution over the area of the Srednebotuobinskoye field using complex lithofacies and cyclic analysis. Based on the description of the core, thin sections, X-ray phase analysis, X-ray fluorescence spectrometry, structural, texture, granulometric analyses and geophysical well logging, a lithofacies scheme was constructed for the time of formation of the Botuobinsky horizon and the horizon was divided into four cyclites. The best reservoir characteristics within the Botuobinsky horizon were established in its middle part (2–3 cyclites) in the deposits of the coastal slope facies, tidal channels and sandy littoral. However, the primary filtration-capacity properties of the Botuobinsky horizon were significantly influenced by secondary processes of salinization, quartz regeneration, anhydritization and dolomitization, which, however, are manifested differently in different facies.

The example of an oil and gas condensate field in the northern part of the West Siberian oil and gas basin in the Yamalo-Nenets Autonomous Okrug demonstrates how applicable the regional data are for sedimentation process awareness in the region to study and how important it is to delve into all multi-level data to build a reliable 3D geological model basis. The comprehensive analysis of heterogeneous geological and geophysical data resulted in developing a sedimentation model of the Upper Tyumen Formation layer. Tidal plain conditions in the littoral zone in areas with predominant clay and mixed sandy-clay sedimentation formed the Middle Jurassic layer in the study area. The bulk of sand bodies are confined to point bars formed as a result of lateral accretion. Mudded channels limit the bar bodies. The qualitatively interpreted seismic data led to identify the layer facies features corresponding to the electrofacies analysis data and core facies. The obtained data confirm the prognostic value of the sedimentation model to be used as a reliable basis for a future 3D geological model.

The article studies a method for dehydrating oil-water emulsions from the Chinarevskoye oil and gas condensate field in Western Kazakhstan using local clay raw materials. Since flooding of productive formations in oil fields significantly complicates the technology of oil production, preparation and transportation, the task of finding cost-effective methods for oil dehydration based on the use of local clay rocks is urgent. The Pogodayevo field in the West Kazakhstan region is rich in clay raw materials, which include the mineral montmorillonite, which has pronounced sorption properties. A study of the composition of the Pogodayevskoye field clays showed that they have an adsorption index of 93.75 mg/g, which indicates their high adsorption capacity and, accordingly, the possibility of using them as sorbents in the technology of dehydrating oil-water emulsions. The pore structure of the clay sorbent, represented by mesopores, was studied. The physicochemical properties of oil from the Chinarevskoye oil and gas condensate field have been studied using chemical and physicochemical methods. The water content in oil from the Chinarevskoye oil and gas condensate field exceeds 75 %, indicating its high water content. Studies have been conducted to determine the optimal amount of bentonite used to dehydrate model 20, 50, and 75 % water-in-oil emulsions, as well as real water-in-oil emulsions using bentonite at different temperature conditions. The optimal concentration of bentonite for dehydrating emulsions has been determined to be 12 % by weight. At a temperature of 50 °C, the rate of water sorption by bentonite clay increases. It has been established that at a temperature of 50 °C, clays dehydrate a 75 % water-in-oil emulsion to 13 % residual water content. The expediency of using bentonite clays of the Pogodaevskoye field as sorbents in the technology of dehydration of water-oil emulsions is shown.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 222417, “Complete Workflow and Case Study for Thermal Dynamic Simulation of CO2 Storage in Depleted Gas Reservoirs,” by Shah Abdur Rahman, SLB; Christna Golaco, SPE, Sharjah National Oil Corporation; and Vladimir Stashevsky, SPE, SLB, et al. The paper has not been peer reviewed. _ Using a case study from the Sajaa Field in the UAE, the authors devised several workflows to establish a fully thermal dynamic simulation case for CO2 storage in a depleted gas reservoir. Several novel workflows were established during this study, including setting up dissolution tables for CO2 and impurities being injected, tabulating the enthalpy of each component, and computing reservoir and caprock formations’ thermal capacity and conductivity. The paper provides guidelines for thermal modeling for carbon capture and storage projects in a depleted gas field. Introduction Situated within the intricate fold/thrust belt of the Oman Mountains, the Sajaa and Kahaif gas-condensate fields are prominent hydrocarbon reservoirs characterized by the Cretaceous carbonate formations of the Thamama Group. Both fields are prolific gas and condensate hydrocarbon producers. The Sajaa field is overlain by a thick sequence of the Nahr Umr formation, which serves as a competent and reliable seal effectively containing substantial volumes of hydrocarbons over geological timescales. Production of the field commenced in 1982. Between 1984 and 1986, the field reached its peak gas- and condensate-production rates. Given their extensive depletion and favorable geological characteristics, the Sajaa and Kahaif fields currently are being evaluated for suitability as CO2 storage sites. Overall Workflow Description The authors focus exclusively on the aspects of dynamic simulation of depleted gas reservoirs for CO2 storage that are unique to thermal dynamic simulation models. The overall workflow is shown in Fig. 1. In broad terms, to convert an isothermal dynamic model to a thermal dynamic model, two primary aspects must be added or modified—fluid models and rock models. In the fluid models for thermal dynamic simulation, it is necessary to model fluid enthalpy and fluid K-values. These additional parameters are crucial for capturing the thermal behavior of the fluids involved accurately. Additionally, in the reservoir-definition or rock models, thermal heat capacity and thermal conductivity must be defined for all reservoir and nonreservoir layers. Once the fluid- and rock-modeling aspects are fully defined, the thermal history-matching model is run to ensure that the history match remains fully intact. After ensuring the quality retention of the history match, the thermal dynamic model is used for predictions. The prediction setup involves a comprehensive process, including setting up well-, group-, and field-level constraints and developing a robust strategy for reservoir development. With these elements in place, predictions can be made using the thermal dynamic model. The complete paper provides a discussion of the fluid-model setup for thermal simulation, including associated equations.

This article examines the advantages of stabilizing crude oil and gas condensate to extract the most volatile hydrocarbons (C1–C4). Stabilization reduces light fraction losses due to evaporation by up to 80% and prevents corrosion of equipment and pipelines along the route from the Karachaganak oil and gas condensate field to refineries. A comparative analysis of effective stabilization methods is presented, including three-stage separation, distillation in a stabilization column, and their combination. Phase equilibrium constants and distillate fractions were calculated using the bisection method implemented in the Pascal programming environment. Based on the calculations, optimal parameters for the three-stage separation process were determined: first stage — 1 MPa, 35 °C; second stage — 0.3 MPa, 35 °C; third stage — 0.1 MPa, 35 °C. These parameters reduce the vapor pressure of stabilized condensate to 66.7 MPa. The three-stage scheme offers advantages such as simplicity and relatively low capital and operational costs. To enhance stabilization efficiency, it is proposed to combine vapor streams from the second and third stages and direct them to a distillation column with 11 sieve trays. The optimized column operation (3.6 MPa, top temperature 26.5 °C, bottom temperature 81 °C) ensures effective separation into methane, ethane, and heavier hydrocarbons (C3+), which are returned to the stabilized condensate stream. The methane-ethane fraction is considered a promising feedstock for the petrochemical industry.

Presented on 27 May 2025: Session 2 The move to risk-based hydrate management has facilitated the development of numerous projects worldwide that were previously rendered uneconomic by the cost of overcoming technical challenges. While literature is available for risk-based hydrate management approaches for oil systems, this paper focuses on the application of these approaches to gas condensate developments. A combination of engineering expertise, operational knowledge, laboratory analyses and modelling techniques is being leveraged to quantify hydrate formation and plugging likelihood in gas condensate fields. The potential for complete hydrate blockage is established by analysing the critical factors for stable hydrate formation and the conditions necessary for blockage. Incorporating the latest hydrate kinetics information provides pragmatic and capital efficient subsea designs for hydrate management. The insights and methodologies shared in this paper demonstrate ingenuity in flow assurance, guiding the implementation of effective solutions and driving project value. To access the Oral Presentation click the link on the right. To read the full paper click here

Relevance. The necessity to locate the main distribution point on the general plan of the assembly point when designing gas fields. During the life cycle of the plant, there is an increase in electrical loads and a change in the nature of their distribution, therefore, when choosing the location of a hydraulic fracturing plant, this circumstance must be taken into account. Aim. To make a decision on the placement of the main distribution point on the general plan of the assembly point, using the methodology for calculating the center of electric loads at the I, II, III stages of the life cycle of a gas field. Object. The second site of the Achimov deposits of the Urengoy oil and gas condensate field. Methods. Mathematical modeling, statistical analysis. Results and conclusions. As a result of the analysis of the literature, the authors have determined the composition of structures and loads of electrical receivers and built the cartograms of loads on the gas field plan with a graphical representation of the center of electric loads. They constructed the potential functions of electrical receivers loads and corresponding line maps of the level of the indicative function for each stage of the life cycle. Cartogram and potential function showed the nature of the distribution of electrical loads and the displacement of the center of electric loads. At the final stage, an analytical assessment, based on the calculation of the center of electric loads at each stage of the life cycle of the gas field, indicated the best location of the main distribution point on the general plan of the assembly point. The authors carried out technical and economic comparison of the power supply system for gas fields taking into account the central power supply in dynamics, and the power supply system without taking into account the central power supply. The results obtained indicate the possibility of choosing the location of the main distribution point at the assembly point site, using the method of calculating the center of electric loads. It is necessary to take into account the change in the nature of load distribution and the development of the electric grid throughout the entire life cycle of the gas field. When designing a power supply system, this will allow achieving better technical and economic indicators.

The article considers the problem of isolation of water and gas inflow in horizontal wells of carbonate fields, especially in the Kuyumbinskoye oil and gas condensate field. Objective. To develop a new silicone composition for sealing in the conditions of fractured reservoirs. Materials and methods. Laboratory and field studies were carried out, including compatibility tests with formation water and oil, as well as strength and filtration tests. Results. The studies showed high chemical compatibility of the formulation with fluids and rapid formation of an isolating mass. In the field, the composition proved its effectiveness when injected into wells with water and gas inflows. Pre- and post-treatment monitoring confirmed flow reduction. Conclusions. The composition enhances insulation durability, lowers operating costs and minimizes environmental impact.

The move to risk-based hydrate management has facilitated the development of numerous projects worldwide that were previously rendered uneconomic by the cost of overcoming technical challenges. While literature is available for risk-based hydrate management approaches for oil systems, this paper focuses on the application of these approaches to gas condensate developments. A combination of engineering expertise, operational knowledge, laboratory analyses and modelling techniques is being leveraged to quantify hydrate formation and plugging likelihood in gas condensate fields. The potential for complete hydrate blockage is established by analysing the critical factors for stable hydrate formation and the conditions necessary for blockage. Incorporating the latest hydrate kinetics information provides pragmatic and capital efficient subsea designs for hydrate management. The insights and methodologies shared in this paper demonstrate ingenuity in flow assurance, guiding the implementation of effective solutions and driving project value.

Background. In the absence of a geologically sound mechanism for the introduction of water into a gas reservoir and a confident a priori localization of potential flood zones, the adaptation of hydrodynamic models has to be carried out based only on borehole data, which entails a high degree of uncertainty, and therefore high prognostic risks. Objective. Reduction of prognostic risks when choosing a pilot production site to increase the component recovery of a field (including by extracting the “matrix” oil of its gas part). Materials and methods. Analysis of the geological and technological prerequisites for massive premature (compared with early design documents) water occurrence in gas wells of the Orenburg oil and gas condensate field from the perspective of modern geodynamic processes developing in a carbonate reservoir with a high degree of bituminosity, principle hydrodynamic modeling. Results. Understanding the geological diversity of the mechanisms leading to water occurrences in the gas wells of the Orenburg oil and gas condensate field makes it possible to create a set of fundamental hydrodynamic models for various reservoir sites. This reduces the uncertainty in the identification of remaining locally trapped gas volumes and the level of risk in the event of an improper selection of a site pilot production for increasing the component recovery. Conclusions. It is assumed that various mechanisms of well flooding were triggered by the attempts to create a gas condensate storage by an explosive method on the eve of development, at the stage of oil and gas condensate field development, in the Kungur salts of the caprock of the Central Dome.