The paper presents new thickness and sandiness maps of the Visean terrigenous strata (Radayevkian and Bobrikian regional stages, Lower Carboniferous) of the South Tatar Arch, constructed using the “Natural Neighbour” spatial interpolation method in ArcGIS Pro software based on the analysis of geophysical survey data for more than 30,000 boreholes.
The interpretation of the maps in combination with the results of sedimentological, ichnotextural and petrophysical core studies, supplemented by the analysis of archival and published materials, provided an opportunity to update the approach to modelling the sedimentation of the terrigenous Lower Carboniferous of the South Tatar Arch. The proposed sedimentation models of terrigenous and coal-bearing sediments take into account the chronostratigraphic data, the karstification of isolated carbonate platforms, the sediment accumulation rates and the ichnotextural characteristics of the sediments. It is concluded that the accumulation and preservation of terrigenous and peat (coal-bearing) sediments differ in duration (0.1 million years vs. 1.5–2 million years) and are consequently associated with transgressive and regressive phases.
The accumulation of terrigenous sediments includes: (a) transgressive eustatic episodes – short-term incursions of a marine basin onto the eroded surface of an isolated carbonate platform, during which silty and sandy, wellsorted bioturbated sediments were accumulated, often with a variety of ichnofossils of marine benthic organisms; (b) the regressive eustatic phase resulted in the predominant erosion of sediments on the arch; whereas sediments in the incisions were largely preserved.
The accumulation of peat (coal-bearing) deposits includes (a) the regressive eustatic phase, during which the vast area of the eastern Volga-Urals region was covered with flourishing vegetation and stable swamp environments were forming in the incisions of the Tournaisian surface; (b) the transgressive phase – the peat was overlaid and buried by transgressive marine silt-sand sediments; then it was compacted and transformed into coal. The alternation of coal-bearing and transgressive intervals indicates the cyclicity of these processes.
The proposed sedimentation models extend the concepts of previous studies and are consistent with the developed maps of thickness and sandiness of the Lower Carboniferous terrigenous sediments, explaining the complex, covering and mosaic distribution of sand bodies over the area, as well as the filling of incisions with sediments of different lithological types.

In this paper, based on a geochemical study of rock samples and fluids, it is proven that carbon-bearing deposits of the Lower and Middle Jurassic complex of Western Siberia on the southern outskirts of the Khanty-Mansiysk and Yamalo-Nenets Autonomous Okrug can generate liquid hydrocarbons. It has been established that the oil-generation potential of carbon-bearing deposits depends on the paleogeographic conditions of burial of the organic matter and the enrichment of rocks with macerals of the liptinite group. The complex of studies included pyrolysis of coals, coal-rich shale of Lower and Middle Jurassic rocks, study of maceral composition and measurement of reflectivity indicators, hydrocarbon and isotopic composition of extracts from rocks, as well as study of the composition of oils from the studied area, selected both within the Jurassic and Cretaceous complexes. The studied area is located in the Frolov megadepression and the South Nadym megamonoclise. The result of the research was the identification of significant geochemical characteristics of an additional source of hydrocarbons – coals, coal-rich shale of the Lower and Middle Jurassic, which had not previously been proven on the studied area, the contribution of which to the formation of oil and gas potential was confirmed by the correlation of hydrocarbon and isotopic characteristics of fluids and extracts from source rocks. Сluster and the principal component analysis were used for genetic correlation of extracts and oils. The conclusions obtained from geochemical studies suggest the possible prospects of Lower and Middle Jurassic deposits from the point of view of detecting hydrocarbon accumulations.

Group and molecular compositions of organic matter from bottom sediments of the northern sector of the Barents Sea were analysed. The sites where bottom sediments contain organic matter of molecular composition similar to that of oil are identified. Thermally mature hydrocarbon compounds detected in extracts from sediment samples indicates ongoing migration from deeply buried strata and fluid discharge processes on seafloor within the studied areas. Molecular compositions of extracts from bottom sediments were compared with and showed geochemical characteristics similar to some series described for the closest onshore to the study areas. That allows an assumption that the source for migrated hydrocarbons identified in studied bottom sediments can be Mid-Triassic organic-rich claystone intervals which are a part of sedimentary succession of the North Barents deep depression.

The article describes a numerical-analytical model for gas breakthrough to a well during the development of oil fields with a gas cap using horizontal wells. The employed semi-analytical model allows describing the process of gas cone development and reproducing oil and gas production parameters from the well by matching to the actual production history using several coefficients. The numerical scheme of the model was implemented as a computational library in the Python 3.6 programming language.
The algorithm was tested on oil deposits with a gas cap in the South Yamal oil and gas region and showed good results in history matching and forecasting calculations. The average calculation time of one iteration being less than 10 seconds allows for multiple model run scenarios using optimization algorithms for automatic calibration to actual production data. The results of the testing show the possibility of achieving satisfactory convergence using automated calibration to the production history. The developed algorithm reduces the workload of specialists in forecasting production, thereby enhancing the effectiveness of decisions made for development optimization.

This paper introduces a method for constructing adaptive reduced-order reservoir simulation models based on the POD-DEIM approach for field development optimization and assisted history matching problems. The approach is based on adapting the orthogonal decompositions bases to the varying model configuration. The method utilizes information contained in the bases of the original model and supplements them with new components instead of constructing a new model from scratch. Adapting the bases significantly reduces the computational costs of building reduced-order models and allows the application of such models to tasks requiring multiple simulations with different configurations. The paper presents an implementation of the POD-DEIM model for a two-phase flow problem and discusses examples of adapting this model to changes in well configuration and geological properties of the reservoir. We propose a generalized approach using POD-DEIM models in combination with the bases adaptation technique to solve optimization problems, such as field development optimization, selection of the optimal well locations, geometries, and well regimes, as well as history matching.

The purpose of this work is to select the optimal method for multi-stage hydraulic fracturing simulation at the wells of a large gas condensate field X in conditions of lowpermeability reservoirs and potential risk of condensate loss in the near bottomhole zone with a decrease in reservoir pressure.
At the moment, there are many ways to simulate hydraulic fracturing, each of which is characterized by its advantages and disadvantages. For specific simulation conditions, it is necessary to choose the most optimal method of hydraulic fracturing simulation, which allows you to correctly simulate all the effects that are expected during development. Within the framework of the current work, the most common numerical methods of hydraulic fracturing simulation were described in abstract, their advantages and disadvantages for specific conditions of field X were reflected. Special attention was paid to the comparison of hydraulic fracturing simulation techniques using virtual perforations and local grid refinement, since these techniques are the most common ways to set hydraulic fracturing in existing hydrodynamic simulators. Scenario calculations were carried out, which made it possible to determine the limits of applicability of various methods, compare the correctness of reproducing downhole effects, quantify the deviation of the calculation results of different methods from the reference calculation. In addition, in the course of the work, various features of the application of the hydraulic fracturing simulation through local grid refinement were described, which were revealed experimentally.
As a result, for multi-stage hydraulic fracturing simulation was used a method in which the cells with hydraulic fracturing are logarithmically chopped relative to the original grid. This method allows to simulate the actual rate of decline in well productivity in conditions of low reservoir permeability, and also allows to simulate in the hydrodynamic model the effect of condensate precipitation in the near bottomhole zone and the subsequent decrease in gas productivity.

The article provides an overview of ionmodified waterflooding technology, also known as low salinity, controlled salinity, or Smart water. This technology is currently considered one of the most promising approaches in the development of oil deposits in carbonate reservoirs due to its economic efficiency and environmental safety.
The article discusses the main mechanisms and processes underlying ion-modified waterflooding and presents the results of laboratory studies conducted on core samples from foreign oil deposits. It includes an analysis of several studies, including contact angle measurements and core flooding experiments on core samples from oil deposits in carbonate reservoirs on the eastern side of the Melekess depression in the Republic of Tatarstan.
It is important to note that the Vereyian deposits explored in this article are not a typical example of test objects for ion-modified water injection. This is because they are characterized by a low reservoir temperature of 23 °C, which suggests that the efficiency of the technology would likely be lower compared to studies conducted abroad, where reservoir temperatures were significantly higher. For example, Darvish Sarvestani et al. studied reservoir conditions at 90 °C, Yousef et al. – reservoir temperature of 100 °C, and Austad et al. examined the Ekofisk field at 130 °C and the Volhall field at 90 °C in Norway.
However, as several studies have indicated, prolonged contact between rock samples and ion-modified water contributes to significant hydrophilization of the rock surface, as confirmed by contact angle measurements. The contact angle decreases from approximately 138.3° to 53.45° after exposure to ion-modified water.
Additionally, the core flooding experiment demonstrated a slight increase in the oil displacement coefficient, reaching 9.2%.
These findings suggest the potential for enhanced oil recovery by injecting Smart water into the Vereyian sediments, although further research is required to confirm the underlying mechanism.

This article describes a method of predicting super-viscous oil deposit development performance by catalytic aquathermolysis process in cycling steam simulation (CSS). This technology involves the injection of an oilsoluble catalyst into the reservoir after several cycles of steam injection and oil production. According to the results of laboratory studies, the effect of catalytic oil upgrading in the reservoir is expressed in non-instantaneous reduction in oil viscosity and increase in sweep efficiency. To assess the effectiveness of the technology on the field-scale thermal numerical simulation model, based on the results of laboratory studies, is used. The oil upgrading process is represented in the model by the oil upgrading reaction and dependence of oil viscosity and residual oil saturation on the degree of oil upgrading. The kinetic parameters of the reaction and the properties of the converted oil are adjusted according to the results of experiments in a high-pressure reactor and tube tests.
Field scale numerical simulation resulted in dependance of catalytic upgrading efficiency on the uniformity of well temperature profile, presence of residual oil and reservoir properties at the effective wellbore radius. It is shown that the effect of catalytic upgrading on a CSS well is determined not only by physical and chemical changes in oil composition but also by adsorption properties of the catalyst itself, heating the wellbore region and matrix and fracture interaction in reservoir. According to simulation results, choosing an optimal catalytic volume and injection scenario allows the recovery of up to 25% of additional oil, that reveals good perspectives of improving steam-based technologies by in-situ catalytic upgrading.

This paper proposes a method for determining the boundary values of open porosity (K_{PO_GR}) and gas permeability (K_{PR_GR}) of porous-type carbonate reservoir rocks using the example of Tournaisian deposits of one of the oil fields of the Republic of Tatarstan. When justifying the boundary values, two databases on core studies are used: 1) on standard core studies (used mainly to calculate hydrocarbon (HC) reserves); 2) on special core studies (used for technological development projects). In the proposed method, the residual oil saturation factor is not a constant, but is taken from flow studies or calculated from core dependencies. When determining the lower limits of porosity and permeability from both databases, approximately the same boundary values were obtained: K_{PO_GR} = 0.11 fr. un., K_{PR_GR} = 2·10^–3 μm² and K_{PR_GR} = 1.7·10^–3 μm² , but they differ from the values, accepted by petrophysicists when calculating the reserves of considered deposit – K_{PO_GR} = 0.09 fr. un., K_{PR_GR} = 1·10^–3 μm² . Such a difference in determining the boundary porosity can significantly affect the calculation of hydrocarbon reserves, technological calculations and field development planning.

Current problems in mature oil fields are high water cut and flow profile estimating of oil and associated brines from different layers. To establish the flow profile in production wells, geophysical research (Production Logging) is traditionally used by lowering special equipment into the well. Production Logging requires production stops and labor costs. Geochemical methods (Production Geochemistry) are used as an alternative solution: sampling is simple and efficient, which makes it possible to cover all the interesting area. Moreover, sampling does not require stopping the well. The geochemical method uses individual indicators of the composition of formation fluids produced from different perforation intervals. In this work, geochemical studies were carried out using wellhead samples from more than 100 wells, with single perforation for carbonate and terrigenous reservoirs. Some wells have joint exploitation of these formations. An automated algorithm was used to identify the distinctive characteristics of each formation based on the composition of the produced brines and oils. Data on the chemical composition of fluids from different development objects made it possible to determine the flow profiles in wells with joint production. Based on the results of the studies, the Devonian reservoir of the field under consideration is divided into 2 parts – northern and southern, which differ in the chemical composition of formation fluids. The same separation of the deposits into 2 parts is noted by field development analysis: over the past 50 years, the main production of oil and associated brines has been concentrated in the southern part of the deposit, confined to the fault, where the active work of the aquifer is assumed. It is recommended to use the obtained data for history matching of the reservoir simulation model.

The article proposes a method for rapid assessment of the initial position of oil-water contacts, oxidized oil zones, transition zones, zones of high and decreasing resistance in the Lower Carboniferous Tournaisian oil deposits at one of the oilfields of the Republic of Tatarstan. As initial data, the values of electrical resistivity of effective interlayers from the catalog of geological and geophysical data, determined from induction logging curves, were used. Well log data for more than 200 wells drilled in elevation areas were used in analysis. The change in the electrical properties of deposits vertically is considered using the average resistivity values of effective interlayers averaged over all wells. Conclusions are based on the results of the done work: according to the resistivity values in massive carbonate deposits of the Tournaisian age, it is possible to distinguish various zones of oil saturation along the vertical; initial oil saturation does not grow exponentially, as in the Leverett function, but linearly in each zone.

Hydraulic fracturing is a technologically complex procedure that is influenced by many factors. Some of them cannot be changed, such as the geomechanical parameters of the target formation or the orientation of the stresses in the formation. But other parameters can be adjusted: proppant type, fluid type or injection mode. In this paper, modelling of the effect of fracture fluid rheological parameters on fracture geometry has been carried out. Two software products, RN-GRID from Rosneft and FracPRO from GTI Energy, were used to create the models, and analytical calculations were performed. Identical models were created in which rheological parameters were changed and changes in fracture geometry were analysed. The presented theoretical data and dependencies can help specialists to form an idea of the processes that take place during the hydraulic fracturing, and more consciously approach the calculations.

The article describes the project being developed for the digital scientific platform “Aggregator of unstructured geological and field data”, which could potentially be important for the oil and gas industry. The use of new intelligent technologies within the framework of this project will significantly improve the efficiency of processing, storage and use of geological and field information contained in various text sources, mainly in field reports.
The main goal of developing a digital scientific platform is to integrate heterogeneous information about the objects of subsurface exploration, which is extracted from reports on deposits of the Republic of Tatarstan. This will create a consolidated database that will become the basis for making informed decisions in the oil and gas sector. The project of the digital scientific platform includes the development of architecture, algorithms and software solutions based on modern methods of text processing and data mining.

The clinoform concept of the Lower Cretaceous of Western Siberia was and remains the scientific basis for predicting its oil and gas potential. At the same time, new challenges and new technological opportunities require its further development. The basis for this can be a modern model independent methodology of sequence stratigraphy, the essence of which is to divide the stratigraphic section into a succession of systems tracts by mapping of all sequence stratigraphic surfaces. At the same time, the choice of the type of surfaces limiting the sequence is carried out already at the second stage on the basis of the expression of the surfaces in the stratigraphic section or the preferences of the researcher.
The wide development of unconformities in the Western Siberian Lower Cretaceous clinoform complex makes it possible to subdivide clinoforms into four systemic tracts: highstand HST, falling-stages FSST, lowstand LST, transgressive TST. The subdivision is carried out by mapping sequence stratigraphic surfaces based on the analysis of stratal stacking patterns. According to the authors, the boundaries of the sequences in this case should be the tops of the TST – the downlap surfaces (DLS), traditionally interpreted as maximum flooding surfaces (MFS). This ensures the consistency of the proposed approach with the clinoform concept.
The named clinoforms of Western Siberia can be considered as genetic sequences of the III order. However, the position of facies in their systems tracts is far from always predictable. For further detailing of facies models, clinoforms – III order sequences should be subdivided into clinoforms – IV order sequences, and subdivide them into systems tracts. But the latter are not always mapped by modern seismic method. Special conditions are necessary for this. Therefore, it is proposed at first to subdivide the III order sequences into systems tracts. Then – to map their thicknesses, and to allocate of their depocenters. Further, within the depocenters (under suitable seismogeological conditions), to define IV-order clinoforms – sequences and their constituent system tracts as a basis for mapping reservoirs and hydrocarbons traps.

The article presents the results of studying four sections of the Bazhenov Formation and the overlying sediments in the central part of the Mansi syneclise, which are based on a comprehensive analysis of the results laboratory lithological and geochemical studies of core material and data from a wide range of geophysical studies of wells. For lithological characteristics, the section of the Bazhenov Formation was divided into five members, which differ in the ratio of carbonaceous, clayey, siliceous contents and carbonate component of rocks. The boundaries of the units were determined by their lithological composition, and then the velocity rectified taking into account GIS. The first two members are characterized by high contents of siliceous and clayey material, the third – a significant increase in the siliceous component, the fourth – increased concentrations of organic matter, which indicates its higher compared to the lower part section oil generation potential. In the fifth member, the content of carbonate material increases, the “coccolithic” interval is divided, and numerous fragments of bivalves are noted. Throughout the section minerals (strontianite, witherite) were discovered in the Bazhenov Formation, indicating that they occurred in diagenesis hydrothermal processes.
In the section of one of the studied wells in the middle part of the Bazhenov formation, a reservoir interval was identified. High variability of reservoir properties of Bazhenov rocks was noted even within one oil-field, which is associated with their secondary transformations of rocks in dia- and catagenesis. It is substantiated, that materials of geophysical studies of wells that does not contain nuclear magnetic resonance data can only be used to identify possible productive intervals, the study of which by laboratory methods will allow establish the presence or absence of collectors in them.

To create three-dimensional models of arcomorph structures based on detailed data of drilling without involving genetic considerations and indirect information, the potential fields method is effective, which consists of finding an approximating three-dimensional function, the set of isolevel surfaces of which are identified with stratigraphic boundaries, using the coordinates of the formation intersection points. For approximation, mainly three-dimensional splines expressed in terms of Green’s functions were used. The main difficulties are associated with the presence of structural unconformities, to take into account which the initial data, and the models built on their basis, are subjected to special spatial transformations. To avoid the influence of high-amplitude arcomorphs on the geometry of the layers of the pre-salt complex, the modeling of the latter was carried out separately from the intensely deformed evaporates and overlying layers. Assaying of the method was carried out at one of the sites in the Caspian Sea. On the study area, according to the interpretation of logging data from 249 wells, a three-dimensional model was created, including several arcomorph structures, and covering the stratigraphic interval from the Emsian stage of the Lower Devonian to Quaternary deposits. The results confirmed the presence of arcomorphs with overturned beds. Such structural forms are poorly fixed by 2D–3D seismic survey methods. The proposed method can be applied in geological studies in the search and exploration of hydrocarbons in salt dome areas.

The paper evaluates an efficiency of the existing rock typing methods for diagenetically modified carbonate reservoirs and proposes a new alternative rock typing index.
Four existing rock typing techniques are applied to the target formation, subjected to considerable diagenetic alterations. Applied techniques do not provide sufficient results in terms of reliable correlation between porosity, permeability and irreducible water saturation, which is crucial for geological modelling. Therefore, a new rock typing index named KØS and calculated as a function of permeability (k), porosity (φ) and irreducible water saturation (S_wir) is proposed for proper characterization of the carbonate formation. Contribution of depositional and diagenetic processes and associated microfeatures into parameters of the index is demonstrated by means of X-ray microCT and NMR experimental data.
Comparative analysis of the proposed index with the existing ones shows that the KØS-derived rock types demonstrate the highest correlation coefficients between the key reservoir parameters. The defined rock types have distinguishable microstructures that confirm validity of the rock classification approach.
All the entities of the KØS index are used for reserves calculations and commonly measured during routine core analysis: this enables its implementation at the most carbonate fields.

The results of a study of the isotopic composition of oxygen and hydrogen of groundwater and dissolved inorganic carbon in oil and gas deposits of the northern regions of Western Siberia, covering a wide stratigraphic range – Mesozoic and Paleozoic are presented. The obtained values are very diverse, covering the intervals from –120 to –50‰ (δD) and from –17 to –2‰ (δ¹⁸O). Such a variable isotopic composition of waters indicates the absence of a unified mechanism for the accumulation of waters and their transformation during the geological evolution of the West Siberian sedimentary basin. The main feature of most of the studied waters is the pronounced values of oxygen isotope shifts relative to GMWL, which generally increase with the age of water-bearing deposits and reach 9‰, which indicates their ancient sedimentary origin.
Variations in the isotopic composition of DIC (from –51.8 to +21.8‰) and its content in waters (from 0.2 to 38.6 mmol/I) indicate a wide range of water burial conditions and processes involved in the conversion of water-soluble carbon dioxide. A general pattern of changes in the isotopic composition of carbon in CO₂ with time, expressed in general form by damped oscillations of the “isotope oscillator”, is revealed. A model of transformation of the carbon isotope composition in carbon dioxide in the closed cycle “atmosphere-soils-deep aquifers” for oil and gas deposits of the northern regions of Western Siberia based on the obtained isotope data is proposed.

Сatagenetic transformations of asphaltenes of organic matter (OM) from recent sediments and fossil rocks were studied on rocks sampled from different sedimentary basins (Timan-Pechora, Mezen, West Siberian, Kuznetsk, Aldan-Maya and Middle Amur) of Russia. Changes in the elemental composition of asphaltenes were analyzed with the Veselovsky’s model of the formation of major groups of fossil fuels using cO parameter (cO = (O/8 – N)/(C/3)) as compared with the total carbon based on elemental analysis. Just as the Van-Krevelen diagram, the plot built in C–cO coordinates for OM of various genetic forms demonstrates a significant difference in the asphaltenes composition evolution during catagenesis. At the same time, the cO parameter has notably increased in asphaltenes of both types of OM. Structural transformations of asphaltenes during catagenesis were identified in the course of high-resolution NMR (nuclear magnetic resonance) spectroscopy. The research results comprise data on carbon distributions in the aromatic and aliphatic groups in the investigated asphaltenes of different type OM of sediments and rocks at different stages of lithogenesis. A correlation between the asphaltene composition and structural parameters depending on thermocatalytic transformations is revealed. The asphaltenes of terrestrial organic matter are distinguished by higher cO values and different carbon yields of aromatics (higher) and aliphatics (lower) throughout the catagenesis phase. The highly transformed marine OM is marked by surge condensation of aromatic rings in asphaltenes, which makes them similar to asphaltenes of the terrestrial type OM.

Integration of petroleum geology methods is the process of applying results of several methods for solving a task or group of tasks in order to reduce the limits of uncertainties in its solution. Since in the oil and gas industry there are a large number of methods, often aimed at solving similar problems, it is necessary to reduce the number of methods solving the same tasks. Thus, the integration of petroleum geology methods means the creation of exploration structures and algorithms for prediction of oil and gas contents. The system can be used not only to select a rational complex of exploration methods, but also to predict petroleum potential in the area by different methods, including IT technologies.

The efficiency of using horizontal drilling technology largely depends on a number of factors, including the geological structure of the productive formation, fracturing, anisotropy, heterogeneity, porosity, and permeability. This necessitates the design of the process of oil inflow to the horizontal section of the well. The article presents analytical and numerical methods used in modeling liquid inflow to horizontal and multilateral wells. The main attention is paid to taking into account the anisotropy of reservoir permeability, the trajectory of the horizontal wellbore and hydraulic pressure losses due to friction.

The functional dependence of thermograms in producing wells has been studied in order to determine the initial temperature distribution along the wellbore. Information about the initial thermal field makes it possible to ensure the reliability of solving the problem of determining the operating intervals in production wells. In this paper, we propose a method for isolating the linear dependence on the thermogram profile in the intervals of the absence of fluid movement (in the sump of a working and along the trunk of an idle well) by constructing a special function – the vronskian. In this paper, it is established that the use of the vronskian can be used to restore the geothermal distribution, as well as to obtain the value of the geothermal gradient and temperature in the analysis of the thermogram. To discuss the possibilities of the proposed method, three cases were used: a model and two thermograms in a real field study. The first option considered is a synthetic thermogram with a quasi-stationary mode of operation of the well. In the second and third cases, the results of thermometric studies in the well with a short-term inflow from the reservoir with the same and different lithological structure of the intervals in the sump are presented. The obtained algorithm can be used to isolate the intervals of linear dependence during express processing of registered thermograms in order to obtain quantitative parameters of the operation of the borehole-formation system.

One of the important tasks of analyzing oil field development is predicting well performance. For this purpose, displacement characteristics are often used, which represent the dependence of some indicators on others. To determine the parameters of these dependencies, regression analysis of historical data is used. Dependences of the choice of watering production wells with water pumped into injection wells, water or the law of the exhausted aquifer.
A feature of displacement characteristics is generally considered to be that they can only be used when fluid flows in the formation are established. This is due to the fact that with the classical approach, displacement of characteristics is not observed in the explicit form of well interference. Therefore, the search for displacement characteristics, with the help of which we can talk about the mutual influence of wells, is an important factor. This is the subject of this work.
Water cut and water-oil ratio (WOR) are related by a well-known formula. The paper proposes regression models for WOR. They obtained the result taking into account the classical logic of the WOR from accumulated oil production.
Water cut is calculated from water saturation. The proposed regression models of water saturation are based on the analysis of equations of theories of two-phase filtration in difference form.
11 watering models were studied, two including classical ones and 9 new ones. Dependencies for reservoir and bottomhole pressures were also developed. The proposed models are intended to analyze the operation of wells during the development of an oil reservoir in an elastic-water-pressure mode. The models were tested on a real field and their effectiveness was analyzed. Some new models perform well in a selection of tests. In particular, all the proposed models give better results than the classical model: the logarithm of the water-oil ratio from the accumulation of oil production.

One of the main tasks of the analysis of gas storage in aquifers-reservoirs is the operational control of drained volumes of gas, the value of which largely depends on the technological and technical and economic indicators of the creation and operation of UGS. An effective tool for solving this problem is the use of gas-hydrodynamic proxy models of formations.
One of such models is presented, which, taking into account the implemented system of group (by assembly points) placement of vertical production wells, can be briefly described as a model of zonal drainage and seasonal interzonal gas flows in the reservoir.
An example of calculations of changes in the cyclic operation of UGS of gas-saturated pore volumes and gas volumes in different drained zones, including in the peripheral poorly controlled zone of the formation, taking into account seasonal interzonal gas flows, as well as the volumes of manmade gas accumulations in the control horizons formed as a result of interplastic flows is given.