Introduction. Hydrocarbon reserves of the Bazhenov suite are classified as hard to recover, and due to the depletion of conventional targets, the suite is the most significant for the development of mature fields.

Aim. The efficient development of the Bazhenov suite requires unified reliable algorithms for identifying net reservoir intervals, determining volumetric parameters based on core and well logging data, as well as for predicting promising areas in plan.

Materials and methods. An integrated approach combining laboratory analysis of core and well logging surveys made it possible to assess prospects of the Bazhenov suite.

Results. The most promising intervals (Packs 1 and 2) with high fragility, which is important for hydraulic fracturing, and low content of organic matter have been identified. The function of laboratory data (nano-permeability) and calculated geophysical parameters (fragility, organic matter content) has been established, which made it possible to identify zones of oil inflows.

Conclusion. The developed algorithms and methods for predicting inflow intervals have made it possible to more accurately identify areas with high potential for oil production, which is crucial for the development of complex targets.

Introduction. Heterogeneity of fluid saturation in the Tyumen Formation reservoirs significantly complicates the correct interpretation of well logging data and building a 2D geological model. Uncertainties associated with reservoir heterogeneity require detailed study. Current conditions necessitate the development of approaches that allow to reconstruct the reservoir structure, taking into account the complicating factors of low permeability and high discontinuity.

The objective of this study is to build a 2D geological model of the reservoir, taking into account the existing fluid heterogeneity.

Materials and methods. This study is based on well logging and core data. A capillary saturation model was built using the Brooks and Corey model. The 3D CDP seismic data was used to build the structural surfaces of the top and bottom of J3 reservoir and to interpret the shale-out zone. The reserves estimation maps were built in Isoline SW.

Results. The fluid type uncertainty analysis for the polyfacial terrigenous sediments of J3 reservoir of the Tyumen Formation are described. A comprehensive set of laboratory core studies, combined with well logging data, established a direct correlation between the degree of oil saturation in low-permeable reservoirs and their porosity and permeability properties, contrary to the general notion that it varies with reservoir height. A single well was used to demonstrate the presence of type I capillary barriers preventing complete reservoir charge within the established oil-bearing contour.

Conclusion. The geological model developed with account of reservoir fluid heterogeneity is capable of most accurate representation of the fluid type distribution patterns in reservoirs. The interpreted capillary barriers and saturation heterogeneity indicate the need for an integrated approach to the interpretation of well logging and core data. The obtained data can be used to update high-water-cut zones in developed fields with heterogeneously saturated reservoirs.

Introduction. The study of the Cambrian carbonate deposits of Eastern Siberia, particularly the Osinsky Horizon (Reservoir B1) of the Chonsk Group of Fields, is challenging due to its complex vertical heterogeneity and intense secondary processes, such as calcitization, which significantly affect the reservoir properties.

Aim. The aim of the work is to analyze the vertical heterogeneity of Reservoir B1, assess the impact of secondary processes on reservoir properties, and develop an improved approach to its geological modeling.

Materials and methods. Based on drilling data, core, and lithological studies (thin section analysis) from key wells, Reservoir B1 was subdivided into four packages. Lithofacies features, reservoir properties, and the distribution of secondary alterations for each package were analyzed. The relationship between calcite content and fracture density was additionally investigated using well-logging data.

Results. Four packages within Reservoir B1 were identified, differing in depositional environments, lithological composition, and degree of secondary alterations. The lower package (up to 40% of thickness) is characterized by a high degree of calcitization, leading to a significant deterioration of reservoir properties. The upper packages are composed predominantly of dolomites with better reservoir properties. No significant differences in porosity permeability relationships between the packages were revealed. No clear correlation between calcite content and fracture density was found.

Conclusion. To improve the reliability of the geological model of Reservoir B1, it is proposed to model each package separately using individual input statistics and settings that account for their distribution patterns. The developed approach is applicable for studying coeval deposits with similar sedimentation conditions in Eastern Siberia.

Introduction. Traditionally, uncertainties associated with the net pay volume prediction in the inter-well space contribute to the greatest challenges in the geological & economic assessment. Depending on the specific features of productive deposits in the areas being evaluated, it becomes necessary to develop universal algorithms for adapting the calculation process.

Aim. The purpose of this work is to optimize large-scale exploration projects by universalizing fluid-saturated thicknesses multi-variant calculations approaches, depending on the quantity, type, and quality of the initial geological & geophysical information.

Materials and methods. An adaptive integrated algorithm for multi-variant calculations using the Workflow function in geological so ware packages has been developed, which provides for more than 2,500 possible scenarios depending on a variety of factors. The algorithm includes calculations auto-adaptation as well as a specific numerical combination for triggering specific cycles.

Results. The use of this algorithm allows for the automation and, thus, significant acceleration of the process of multivariate geological assessment of fluid-saturated volumes.

Conclusion. The adaptation of multi-variant calculations increases the large-scale geological exploration projects value at the exploration stage, both in terms of reducing the time & labor required, and in terms of the ability to calculate additional intervals within the allocated time for geological evaluation.

Introduction. The presence of unidentified oil rims during the development of gas deposits can lead to problems in gas production. If it is impossible to collect conditioned oil samples, the only way to obtain the characteristics of the oil rim is to conduct laboratory studies of the oil-saturated core. However, the presence of petroleum hydrocarbons in the composition of hydrocarbon-based drilling fluids leads to an overestimation of the Kn values during petrophysical studies and erroneous detection of “light” oil by pyrolysis data.

The aim of the work was to clarify the characteristics of the oil rim (thickness, oil saturation coefficient) of a large Cenomanian deposit in one of the fields in Western Siberia based on the results of the analysis of a historical core with traces of penetration of hydrocarbon-based drilling fluid filtrate.

Materials and methods. To assess the properties of the oil rim, the authors developed a special laboratory research scheme, including petrophysical, pyrolytic and chromatographic studies of the core and rock extracts, as well as an auxiliary stage consisting in determining the pyrolytic profiles of Cenomanian oils of different densities to plot the dependence of oil density on pyrolysis parameters.

Results. Based on the data of pyrolysis studies of core samples, the density values, “group” composition of the oil phase were estimated and the oil saturation coefficient values in the intervals of the oil rim of the gas-saturated formation were calculated. In the course of the studies, an innovative methodological approach to assessing the saturation nature, quantity and properties of the oil phase in the oil rim of the PK1 formation of one of the fields in Western Siberia was developed and implemented. The methodological approach is based on the results of pyrolysis studies of core samples using core photography data in UV, chromatography and petrophysical studies.

Conclusion. The developed methodological approach has demonstrated high efficiency and promptness of data acquisition and is recommended for express assessment of hydrocarbon phase properties in the core sampling interval when implementing complex core study programs from gas-saturated formations. 

Background. Well coning is a top complication for reservoirs with high-viscosity oil and bottom water. The main reason is the higher mobility of bottom water relative to oil. Premature well watering leads to a decrease in oil recovery factors (ORF) and the economical efficiency of field development. Under these conditions, preventing or slowing well coning requires a method that allows monitoring the current position of the OWC.

Aim. The main objective of this study is to develop a new method for monitoring water coning in high-viscosity oil reservoirs. This is necessary for selecting the optimal operating mode for horizontal wells. The skin factor is proposed as a diagnostic indicator: it decreases as the water cone rises toward the horizontal well.

Materials and methods. The study was conducted using a three-phase dynamic model with. At the first stage, the position of the horizontal well relative to the oil-water contact (OWC) was varied: 1, 3, 5, 7, and 9 meters above the OWC. For each case, pressure buildup curves were obtained, and their interpretation in specialized sok ware enabled the determination of the skin factor. Next, the nature of the change in the skin factor depending on the well operating mode was analyzed. Additionally, a sensitivity analysis was performed, assessing the impact of changes in boundary conditions, petrophysical properties and geological structure (presence of shale breaks and a gas cap).

Results. All the calculations agree with the idea of «choking» the liquid inflow by the oil rim. Skin depends directly on the distance to the OWC, and inversely — on the current water-cut (water cone height). It was demonstrated that the methodology is applicable across a wide range of geological and physical conditions, except for cases involving shale breaks that screens water inflow to the well.

Conclusions. The proposed methodology, based on skin factor monitoring, is an effective methodology for diagnosing coning and can be used to optimize the development of heavy oil reservoirs. Specific parameters of the monitoring technique, such as the method and frequency of skin factor determination and limit values, must be established individually for each formation, taking into account its specific characteristics. 

Introduction. Standard waterflooding in the development of low-permeable reservoirs may be ineffective due to low water injection rates. In this regard, gas methods of enhanced oil recovery are particularly relevant due to the high mobility of gas which allows to reach the required injection rates. Also, if miscible injection is possible, this will maximize the oil displacement efficiency. However, due to the high mobility of gas and the presence of highly permeable channels in the reservoir, the gas efficiency can be significantly reduced due to its premature breakthrough to production wells. WAG injection can significantly reduce the probability of gas breakthrough and thereby increase the gas sweep efficiency while maintaining relatively high injection rates.

Objective. Evaluate the performance of miscible WAG (water alternating gas) injection in heterogeneous low-permeable reservoirs in West Siberia.

Materials and methods. The study evaluates gas injection technology on a composite flow simulation model based on laboratory studies of WAG miscible injection. In this paper, based on the results of a series of slim-tube experiments on gas-oil displacement, the possibility of achieving miscible displacement in reservoir conditions was assessed. Low-pressure gas of a treatment system (wet gas) demonstrated high displacement efficiency not only in a slim tube (ED — 0.94), but also on core samples (ED — 0.695). Experiments on additional displacement of oil from a core column at WAG conditions showed an insignificant increase of ED — 0.035. At the same time, the water and gas permeability in the WAG cycles decreased by 5 and 30 times, respectively (the value for gas is given relative to the basic gas injection cycle), which will have a positive effect on the process of redistribution of water and gas flows in a reservoir.

Results. Based on the results of numerical runs of sector reservoir models, it was found that despite the miscible nature of displacement and a high degree of permeability homogeneity within a reservoir, the wet gas, due to its high mobility, does not allow achieving high sweep efficiency and, therefore, high oil recovery factors. The option of wet gas injection in WAG conditions has a high potential for increasing oil recovery in both short and long term.

Conclusion. The WAG technology, despite an insignificant increase in ED in the core experiments, allows increasing the specific performance of gas injection by an average of 4.4 times compared to continuous wet gas injection due to an increase in sweep efficiency. At the same time, both options of wet gas injection allow achieving an increase in oil recovery compared to the basic flooding option: the average oil recovery factors for water injection, continuous wet gas injection, and wet gas injection options in the WAG conditions were 0.21, 0.3, and 0.48, respectively.

Background. For maintain and increasing oil production, in modern world it is required to development of hard-to-recover reservoirs, at the same time costs of building wells are increasing and barrel price is at a low level. All of that leads oil Companies to find new solutions and optimize costs. In this article, the authors show one of direction for optimization hydraulic fracturing, where they saw the potential for partial replacement ceramic proppant agent to a cheaper option, fractional sand. The work demonstrates the entire process, from finding suitable materials and suppliers to conducting calculations in various simulation tools and launching experimental work.

Materials and methods. The paper describes the entire process of investigating relationships, from the initial idea to its implementation in practice. It gives a basic assessment of the choice of a solution based on the geological conditions at the development sites and the properties of available proppant agents. This work allowed identifying boundary criteria for fractional sand and outlining a strategy for its implementation. Computational modeling and analytical sok ware, as well as production forecasting using a hydrodynamic model, became additional tools for experimental work. 

Results. The evaluation of the results from the fractional sand research has allowed establishing the criteria for its use, as well as formulating requirements for product suppliers. A method for evaluating potential has been developed, which allows for calculating the possibility of replacing proppant with sand in any geological settings. To reduce the risk of failing to achieve the desired production level, a strategy has been chosen to gradually increase the proportion of sand used in experimental work, with long-term monitoring of well performance and comparison with other wells in the area. At some facilities, a 30% replacement of the ceramic proppant agent with fractional sand has been achieved without loss of production, which is a strong indicator of the effectiveness of the approach and validity of the initial theory.

Conclusion. The direction of optimizing the cost of hydraulic fracturing using fractional sand has become an effective solution for the company. At the same time, the authors note that, in addition to product quality, an important and fundamental element of further development of this solution is its cost. 

Background. The work describes one of the new approaches to optimizing the method of hydraulic fracturing, aimed at increasing fracture length, reducing its height propagation, and enhancing the effectiveness of proppant placement within the targeted interval by lowering the average overall viscosity of the fracturing fluid. The target applications for this solution are development systems without fracture length limitations and candidates with quality hydrodynamic connectivity in the well-reservoir system.

Materials and methods. The paper outlines the conceptual and practical approach of the technological solution “LD-FRAC” (Low Damage) used in the Gazprom nek company group. The fundamental principle of the solution involves the interval-based pulsed delivery of a crosslinking agent while performing the main hydraulic fracturing. In the presence of increased friction in the near-wellbore zone, the approach allows for a seamless transition to a standard classic implementation (cross-linked guar-borate system), which, in turn, reduces the time loss costs during the hydraulic fracturing on the well pad.

Results. The authors thoroughly examine the company’s experience, including field trial materials and methods, as well as schemes for adapting the technology. The data presented demonstrates how a competent approach and modeling of the proposed solution can reduce water cut in production and yield additional hydrocarbon recovery due to less fracture clogging and increased fracture half-length. Moreover, the approach potentially allows optimization of the development system when completing horizontal wells with multi-stage hydraulic fracturing.

Conclusion. This work reflects the successful experience of implementing the “LD-FRAC” technology based on operational efficiency. The potential of the solution, in the long term, allows for the optimization of development systems with horizontal wells that undergo MSF (multi-stage fracturing), where azimuthal fracture projection along the horizontal borehole is anticipated, through the reduction of stage numbers and enhanced propped half-length. The considered solution can also provide advantages in reducing chemical costs (crosslinking agent) without compromising the effectiveness of the technology, thus improving the economic profitability of projects developed with the application of hydraulic fracturing technology.

Introduction. The UCS (unconfined compressive strength) parameter is the unconfined compressive strength of rock, which is a significant physical parameter used to describe strength state of rocks. During drilling, load on wellbore is redistributed depending on the inclination angle. The research introduced the concept of anisotropy coefficient of strength, which is a quantitative characteristic that reflects the degree of reduction in rock strength depending on the orientation of the samples in different directions relative to the applied load.

Aim. The aim of the work is to consider the anisotropy of strength properties and identify its influence on the stability of the wellbore during drilling.

Materials and methods. This article presents a review of the most well-known and practically relevant methods for estimating UCS values, which describe measurements of uniaxial rock compression based on elastic, acoustic, and other physical and mechanical properties of rocks. The influence of ultimate strength calculated by different methods on failure gradients is compared. Based on the interpretation of core data, dependences of ultimate strength on core samples cut at different angles (0°, 30°, 45°, 60°, and 90°) are constructed. 

Results. Anisotropy of strength properties was researched, and its impact on borehole stability was identified. The orientation of the sawn samples was adjusted to match the zenith angles during drilling. A general trend in tensile strength variation depending on the zenith angle of drilling was demonstrated. A collapse gradient assessment using the Mohr-Coulomb method, using the tensile strength curve for standard conditions and accounting for rock strength anisotropy, was considered.

Conclusion. The results of the research make it possible to clarify the risks associated with drilling wells in open-hole instability intervals and to assess the stability of directional and horizontal wells. 

Introduction. Geochemical studies of core samples are widely used to characterize the composition and origin of reservoir fluids. However, the reliability of data may reduce due to contamination by hydrocarbon components of drilling fluids, which alter chromatographic and biomarker characteristics.

Aim. To evaluate the effect of hydrocarbon additives in drilling fluids on core geochemical data and to demonstrate contamination patterns observed in wells from different regions of Russia.

Materials and methods. Core samples from three wells located in the Orenburg region, Khanty-Mansi Autonomous Okrug, and Yamal-Nenets Autonomous Okrug were analyzed. Bitumoids were extracted via solvent chloroform extraction. The extracts were fractionated by group-type analysis. Saturated and aromatic  hydrocarbon fractions were examined using gas chromatography and gas chromatography-mass spectrometry. Principal component analysis was applied to distinguish clean and contaminated samples.

Results. Samples were considered contaminated when they showed clear signs of hydrocarbons that did not belong to the native organic matter. Chromatograms typically displayed a strong naphtenic hump and irregular or series of n-alkanes in such extracts. The fraction composition also changed: saturated hydrocarbons dominated, while aromatic compounds, resins, and asphaltenes were noticeably reduced. Because of the mixing between native extract hydrocarbons and drilling-fluid additives, key biomarker ratios became unreliable and could not be used for genetic interpretation. Statistical analysis further confirmed this pattern: clean and contaminated samples formed separate clusters, with contaminated ones grouping closer to the composition of drilling-fluid hydrocarbons.

Conclusion. Hydrocarbon additives from drilling fluids can significantly distort the geochemical characteristics of core extracts, affecting chromatographic patterns, group composition, and biomarker ratios. To ensure more reliable interpretation, it is important to record the composition of drilling fluids, analyze them together with core samples when possible, and use statistical tools to identify and exclude contaminated material. 

Introduction. In the context of unstable oil prices, cost reduction has become critical. New technologies allow for faster, safer, and cheaper well repair without production losses. The revolution in well repair has arrived: from mechanization to autonomous systems. Modern challenges require new solutions, and we strive to follow this trend by implementing advanced robotic systems. The value of the model, combined with technical solutions, allows us to increase the company’s capitalization in real-time. 

Aim. The main technological challenge is to perform work on wells with abnormal reservoir pressures without killing them. Testing new approaches and using high-tech equipment for routine and major well repairs.

Materials and methods. At the moment, various technological solutions have been tested, and approaches have been identified for each type of well, allowing for the regulation of the technological process. However, working with wells with abnormal reservoir pressures requires different, high-tech methods. Well killing is the first preparatory step before the start of the well’s “life” cycle or during the production process before scheduled repairs, and it is one of the most expensive expenses due to the specific features of the productive horizon, such as abnormally high or low reservoir pressures. This article presents a promising mobile installation for repairing wells under pressure without the need for killing.

Results. During the testing and evaluation of the installation in the Far North, there has been a positive trend in reducing the repair time in wells with abnormal reservoir pressures. The productive time ratio is at 90%, and there is potential to achieve a minimum level of unproductive time. The proposed method of well repair will help reduce the number of HSE (Health, Safety, and Environment) incidents and mitigate the risks of gas and oil spills.

Conclusion. The new high-tech mobile Snubbing Unit can be considered a breakthrough technology for well repair in the Russian Federation, with the potential to reduce well killing costs by up to 100%. 

Introduction. At the considered filed, complications in the form of differential sticking, tight hole events and slack offs during tripping operations, as well as mud losses of various origin and intensity were recorded during drilling. In view of the fact that approaches to eliminate a given set of complications conflict with each other, drilling recommendations suggestion is extremely difficult for a given cross-section.

Aim. Approach for comprehensive analysis of drilling complications development as well as their causes identification using additional information not included in the standard geomechanical modeling workflow.

Materials and methods. The study was carried out for Miocene and Paleozoic sediments. The developed approach is complementary to the standard geomechanical modeling and is based on the additional data introduction: mud logging, information on the complication development process, physical and chemical parameters of the drilling mud.

Results. A geomechanical model for the considered wells is built, the mechanisms of different types of complications are identified and recommendations for drilling new wells are given.

Conclusion. Additional data introduction in support of geomechanical modeling provides valuable information on the causes of complications and allows for a substantial expansion of thedrilling recommendations list. 

Introduction. Development of design documentation for offshore well construction in the current market conditions is a multifaceted, lengthy, and complex process. Therefore, starting from the conceptual model development stage, it is essential to leverage accumulated experience in this field and evaluate project implementation methods.

Aim. The main objective of the Project described in this article is the construction of directional gas production wells using a cluster method using offshore fixed platforms or floating drilling rigs in difficult conditions due to the presence of carbon dioxide and hydrogen sulfide aggression in the produced fluid at the field, as well as due to difficult ice conditions in the area of the offshore field planned for development.

Materials and methods. Due to the need to consider various project implementation options and select the most promising ones within the framework of a Project to develop deposits or promising structures on the shelf, an approach was proposed that provides for the identification of separate stages of the sequential conceptual design of offshore wells, including an assessment of possible risks associated with complicated conditions that must be taken into account in this process.

The result. The article describes approaches to conceptual design that can be used in similar projects for the development and development of offshore fields in difficult conditions, and will allow a comprehensive review and analysis of various aspects when making decisions in favor of a particular development option, without resorting to detailed design.

Conclusion. The approach proposed in this paper can be applied in the conceptual design of offshore well construction by engineering, oil and gas companies, and can also be used in the training of specialists from oil and gas educational institutions. 

Introduction. The digitalization of the oil industry includes “Digital Core Analysis” — a technology for creating accurate digital twins of rocks. This enhances the informativeness of research and the efficiency of project decisions.

The aim of this work is to develop a method for constructing a digital mineralogical model of core samples using computed tomography and scanning electron microscopy combined with an energy-dispersive spectrometer attachment.

Methods. Rock samples were studied using scanning electron microscopy combined with energy-dispersive spectroscopy, computed tomography, X-ray diffraction analysis, X-ray fluorescence spectroscopy, and petrographic examination of thin sections.

Results. Based on the proposed approach, a method for constructing a digital core model has been developed. The method allows for the reconstruction of a digital three-dimensional mineral model of the core. This is  achieved by using two-dimensional elemental distribution maps obtained from a standard scanning electron microscope with integrated energy-dispersive spectroscopy, applying the proposed algorithm for recalculation into mineral composition, and a three-dimensional model of the rock skeleton (matrix) obtained by computed tomography. Based on the obtained model, quantitative calculations of mineral composition can be performed. Verification of the obtained results is carried out through mineralogical studies.

Conclusion. The successful verification of the proposed method with traditional mineralogical studies indicates that the proposed method is a reliable tool for obtaining a digital core model based on standard equipment, without the need for expensive complexes with unique sok ware. 

Intruduction. The article discusses an approach to automating the development of infill drilling business cases for brown fields.

Aim. The aim of the work is to develop and test a module for the automated search for promising zones and placement of the project wells (“AVNS”) for generating infill drilling business cases at brown fields, which allows to reduce the influence of subjective factors and labor costs.

Materials and methods. The developed module includes the following stages:

• pre-processing of geological and production data;

• constructing an Opportunity Index map; 

 • clustering of promising target zones and placement of project wells;

• calculating well start-up parameters;

• assessing economic efficiency.

The algorithms are implemented using machine learning methods, statistical analysis, and common analytical approaches. Testing was conducted on data from more than 40 productive formations.

Results. A retrospective analysis showed high accuracy of the recommendations, comparable to expert decisions, with moderate coverage. Furthermore, untapped prospective zones were identified, indicating additional drilling potential. A key practical result was a reduction in labor costs for business case preparation by 20%.

Conclusions. The study demonstrates that an automated approach can enhance the efficiency of drilling planning for brown assets; however, it requires further development in terms of improving input data quality, refining algorithms, and integrating with other planning systems. 

Introduction. The formation of gas hydrates in natural gas collection and transportation systems is a serious technological problem that can lead to complete pipeline closures, emergency production shutdowns, and significant economic losses. The main method of preventing hydrate formation is the dosing of inhibitors such as methanol or monoethylene glycol (MEG). The cost of these reagents accounts for a significant proportion of the operating costs of the fields, and their overexpenditure due to suboptimal dosing remains an urgent problem for the gas industry.

Purpose. Development of sok ware for dynamic calculation of optimal inhibitor dosage in real time.

Materials and methods. Within the framework of this work, a comparison of various methods for calculating the optimal dosage of the inhibitor using specialized sok ware, empirical calculation formulas, as well as instructions and rules of gas producing organizations was carried out.

Results and conclusion. The developed sok ware solution is integrated with the field’s automatic process control system, providing automatic dosing based on calculated data. Industrial testing at the gas field demonstrated a 40% reduction in inhibitor consumption at bush sites and gas collection networks compared to the previous period of operation. The obtained result confirms the economic efficiency and practical applicability of the proposed approach to optimize the consumption of methanol.