This report represents the findings of a survey of managers and specialists of state and private enterprises from oil and gas sector of the Russian Federation. The survey findings reflect technological needs of the industry, plans for technological development of the enterprises in the short-, medium- and long-term periods as well as the readiness of enterprises for technological cooperation.

The article demonstrates the results of experimental and field studies of the thermal foam-acid treatment technology with the use of water solutions of heat and gas generating system. The potential temperature of the heat-generating reaction upon mixing of agents was estimated in laboratory conditions and the physical and chemical properties of acid solutions were determined. A series of filtration experiments was conducted on treating dolomitized core samples with a basic hydrochloric acid solution.The constant of the rate of reaction between the basic acid solution and dolomitized carbonate rock was determined based on the experiment results. The article provides a brief analytical overview of world experience of the thermochemical treatment of the bottomhole area. The technology selected for the tests called thermo-foam-acid and implies the step-by-step injection of water heat and gas generating solutions with an addition of surfactants and an initiator into the bottomhole area. The heat-generating reaction is accompanied by the generation of a large amount of heat, gases and hot foamed acid. Heating melts high molecular weight oil compounds, washes oil sheen from rock surface and increases the speed of its dissolution with hydrochloric acid. This foam acts as a diverter for the next portion of active acid and prevents undesired stimulation of high-permeability interlayers and fractures. Surfactants in the acid solution increase its ability to penetrate pores and microfractures. The physical modeling of a thermal foam-acid treatment has been performed. Arlanskoe (Kashirskian-Podolskian deposits) and Nadezhdinskoe (Famennian stage) fields where carbonate formations are characterized by high and increased oil viscosity, low reservoir temperature, fractured and dolomitized reservoirs were selected as a site to perform field tests. Well operation at these formations is complicated by the precipitation of asphaltenes, resins and paraffins in the bottomhole area. Solution injection parameters were recorded during treatments based on this technology. The technological efficiency of this treatment was confirmed based on bottomhole pressure and temperature changes during injection operations. Technology efficiency was analyzed and the well flow rate was monitored based on the field test results. The main stages of this work are shown in Figure 1. Figure. 1 Project stages

Nowadays, the vast majority of the oil fields of the Republic of Belarus are at the last stage of development. In this connection, the goal of Belarusian oil industry is to search, to explore and to develop ultra-low permeable tight fractured carbonate rocks. Commercial production of such resources is only possible with the use of advanced stimulation methods, such as hydraulic fracturing / multi-stage hydraulic fracturing. Taking into account the features of tight carbonate rocks, the use of conventional hydraulic fracturing technologies cannot provide optimal results, and therefore, selection of more advanced approaches to hydraulic fracturing is necessary. Selection and optimization of technologies based on theoretical research is not possible, instead it requires practical implementation, and according to our experience, flexibility in decision making. This article presents the experience of unconventional reservoir development in the Republic of Belarus from 2014 to 2020. We briefly described the main technologies used and how these technologies evolved depending on the resulting operational and economic effect. The technology of repeated multi-stage hydraulic fracturing in an unconventional reservoir is described; the possibility of producing from previously untapped reservoir zones within the horizontal wellbore by creating additional flow channels (hydraulic fractures) was confirmed.

Production history fitting in Weiyuan shale gas shows that the length and height of supporting fractures are short, which limits the long-term conductivity of fractures. Due to the limited volume of reconstruction, the production decreases rapidly, which makes it difficult to achieve the purpose of economic and effective exploitation. In view of the above problems, an enhanced hydraulic fracturing technology (EHFT) which has been verified and applied is proposed to increase effective SRV. according to the different characteristics of shale reservoir, EHFT optimizs the performance parameter of fracturing fluid and matchs different modes of proppant injection, which can be classified in 4 major patterns, including modes of proppant injection in long/short slug type and densifying proppant injection in long / short slug type. First, based on brittleness evaluation and mineral composition, and combined with interpretation results of the natural fracture, the pumping plan is made according to the design goal. Then, modes of proppant injection is adjusted and optimized in real time through the construction curve and micro-seismic data during fracturing. The hydraulic fracture propagates along the dominant channel in the process of fracturing and there is the risk of the fracture communicating with the adjacent well. The fracture control technology of multi cluster perforating can effectively avoid it. Through field application, the following conclusions are drawn: (1) For reservoirs with high clay content, high viscosity fracturing fluid is recommended to improve the fracture width and reduce the complexity of construction; modes of proppant injection in long slugs of low concentration can control the construction scale, improve quality of proppant per meter, establish continuous fracture support and improve the long-term conductivity; modes of proppant injection in short slug type can control the fluid loss and avoid the occurrence of complex conditions, which is especially suitable for reservoir with natural fracture. (2) In the process of fracturing, the combination of various modes can achieve good results through real-time analysis and judgment. (3) The effectiveness of EHFT is verified by construction parameters, fracturing curve and micro-seismic monitoring. The construction scale (total volume of fracturing fluid) is reduced by 10%; quality of proppant per meter is increased by 10-20%; the fluctuation range of construction pressure is controllable/small; and the SRV and micro-seismic events are significantly increased. (4) The test production of well A which is the highest in Weiyuan is 71.2×10 4 m 3 with this technology. EHFT is suitable for the complexity of shale reservoir reconstruction. Multiple modes of real-time control can reduce the occurrence probability of complex conditions, improving the effective SRV and achieving efficient fracturing. Most importantly, the technology is feasible and effective in the overall goal of cost reduction and efficiency increase

As the number of stages of hydraulic fracturing along the horizontal wellbore increases, the cost of fracturing starts to exceed the cost of drilling the well. Therefore, the issue of costs optimization for hydraulic fracturing in general become highly important problem. In this regard, for optimization calculations, it is necessary to operate with such important geometric characteristics of fracture as half-length and height of the fracture, which can be determined by logging, well-testing and micro-seismic studies. This paper analyzes all types of studies to determine the geometric characteristics of the fracture, except its width. Logging surveys, which have been carried out on vertical and inclined wells, allow to determine with some degree of accuracy the height of the fracture, provided that the conditions of applicability of these surveys considering well azimuth and inclined angle in the zone of fracturing & logging. Among the logging methods that have been applied to that kind of problem, the highest priority in terms of the reliability of the results obtained is given. Well testing allow us to determine the effective half-length of a fracture, but with some limitations. Micro-seismic studies allow comprehensively and in three-dimensional view to determine the configuration of a fracture in a orientational well or a system of fractures in a horizontal borehole to a certain degree of accuracy.

The Company has recently completed the first stage of a large-scale program for production of hard-to-recover (HTR) oil reserves from standard terrigenous reservoirs. This program is being worked on within the framework of the Optimal Completion Technologies and Operation Parameters of Oil Wells in Low-Productivity Reservoirs technology project implemented within the Company's perimeter. A high-rate hybrid multistage hydraulic fracturing was successfully performed on a number of horizontal wells at the Achimov Formation reservoirs thus confirming the ambitious well productivity plans. The primary goal of the project was to verify the hypothesis that the sweep area can be increased by means of a high-rate hybrid hydraulic fracturing; the next goal is to check the hypothesis that a developed network of fractures, or stimulate reservoir volume (SRV), can be formed at a hydraulic fracturing injection rate exceeding the standard values by 3-4 times. Keeping in mind the tasks of increasing the drainage area and connecting separate zones of highly compartmentalized reservoirs with each other, the basic hydraulic fracturing technology for the design purposes was a high-rate hybrid hydraulic fracturing with an injection rate of up to 12 m3/min and a combined schedule. At the preparatory data processing and interpretation stage, issues in each discipline involved – petrophysics, geology, geomechanics, and hydrodynamics – were worked out in detail and modeled. The design project of a high-rate hybrid hydraulic fracturing treatment has undergone many optimization iterations in the Planar 3D module, with further testing of the anticipated effects on a hydrodynamic simulator using unstructured three-dimensional PEBI grids. As a result of multi-variant modeling performed by a cross-functional team, a universal hydraulic fracturing design was created which predicted high efficiency of the treatment to create both the SRV and the planar fractures. To make the results of the performed pilot work more reliable, a wide range of studies was performed including production logging tests in horizontal wells with various completion systems. While assessing whether formation of the SRV is possible, downhole micro-seismic monitoring was performed, and downhole pressure was measured at neighboring wells. In the real conditions of the tested target reservoir, formation of the SRV was not confirmed at the actual injection parameters. The Planar 3D module, coupled with the hydrodynamic simulator, is an efficient tool to optimize design of the hybrid hydraulic fracturing treatment. The giant half-lengths of planar fractures predicted in the hydraulic fracturing modeling software have been proved by micro-seismic monitoring and pressure response at submersible pumps of the neighboring wells. At one of the stages, a high-rate hydraulic fracturing with 125 tons of proppant was performed entirely with a hydraulic fracturing fluid based 100% on a synthetic gelatinizing agent which showed the greatest fracture length. The Company pays great attention to this technology solution too – several tests have been initiated with respect to ‘pure’ hydraulic fracturing fluids, and work is underway to develop guideline and methodology documentation on quality control. Results of the project have changed the vision of optimal methods for stimulation of the Achimov low-permeability reservoirs. In the absence of the SRV, formation of long planar fractures by means of a system of horizontal wells with low-density spacing can increase economic viability of currently uneconomical fields or separate reservoirs (zones). The novelty of this work consists in the achieved level of integration of model values from various disciplines with the actual data. The initial and current parameters of stimulated wells demonstrate a broad perspective for optimizing the HTR reserves development system for a standard terrigenous reservoir. Successful reservoir stimulation by high-rate hybrid multistage hydraulic fracturing (MSF) opens the way to even bigger projects that envisage drilling horizontal holes up to 2,000 m long and building wells of the TAML-3 level of complexity.

In this paper, some features of conducting experiments on core samples to determine mechanical properties were established. Detailed description for such type of testing is poorly described in regulatory documents (Russian State Standard, ASTM). Problem of specific test methods selection in accordance to task before the geomechanical modeling is considered. For the most issues, a series of experiments to build a failure envelope is required. Details of sample preparation for compression tests are regarded. In particular, the advantages and disadvantages of different methods for preserving in-situ core saturations are discussed: the collection of an isolated core with subsequent conservation or the preparatory work with the extraction, drying and saturation of samples. While conducting multi-stage compression tests for building Mohr circles, chose of the right moment to stop the loading stage has a significant effect to prevent destruction of the sample in the early stages. This paper demonstrated that for specimens characterized by a shear failure type, it is recommended to focus on the plot "axial stress - volumetric strain". In particular, the inflection point of the curve, that is the moment of reaching the maximum value of volumetric deformation could be selected as a criterion for the loading stage termination. For samples with high porosity, a complete testing cycle to build the Mohr circles and the entire failure curve is given.

The article describes the theory of "clamped" water to justify the position of the oil-water contact of the reservoir, exposes in detail the experience of applying this theory on the example of an oil reservoir in Famennian organic deposits of the Vostochno-Lambeyshorskoye field of the Komi Republic. During the field development, geologists have encountered a problem of different oil-water levels established in different parts of the structure, which is determined by well data with a high degree of confidence. The analysis of reservoir pressure data shows, that the separation of the reservoir into tectonically shielded blocks with different levels of water-oil contact is impossible. According to the results of seismic facies modeling and sequence stratigraphy, there were not identified any significant channels that could separate the reservoir by area. The solution to the problem of substantiating the oil-water contact was found by applying the theory of "clamped" water. The idea of this theory is that during the migration of hydrocarbons into the trap, controlled by lithology and faults, there remain the so-called hydrodynamically isolated "pockets" (hereinafter referred to as "pockets") in which the formation water is sealed with oil and the oil-water contact is fixed at the level of the structure bend. The article describes the mechanism for the formation of such "pockets". In the issue, a new conceptual model of the Famennian reservoir of the Vostochno-Lambeyshorskoye field was created as a layer-uplifted deposit, controlled by lithology, with different horizontal oil-water levels. The oil-water level is gradually increasing from north to south, along the path of hydrocarbon migration from the source rock to the reservoir. Oil-water levels are controlled by structural inflections defined on the maps of the reservoir bottom.

This article discusses the problem of creating a hydrogen storage in an aquifer. It is assumed that the process of hydrogen injection and the life cycle of its storage should provide the most complete reverse production of the injected gas in a few years. The features of injected gas distribution in an aquifer are considered, taking into account a number of parameters. For example, the effects of gas breaking through a cap rock and fluids migration under influence of natural water flows from aquifers associated with the target reservoir. An effective storage and subsequent production system are proposed allowing to control geometry and volume of gas bubble in the reservoir. The results are obtained on the basis of large-scale 3D geological and hydrodynamic modeling of filtration through porous medium of a multicomponent system in the form of hydrogen, methane and water mixture on synthetic 3D models. Corresponding studies were performed on a certified hydrodynamic simulator using a composite model. Large-scale 3D geological and hydrodynamic modeling made it possible to justify the method of compact hydrogen storage in an aquifer. Closed systems, without contact with large volumes of water in adjacent aquifers, do not allow significant gas volumes to be stored under technologically realistic parameters. Presence of an active aquifer dramatically changes injected gas configuration and facilitates its migration from the zone of possible reverse production. The necessity of creating a permanently operating associated water injection system is substantiated to control geometry of the created hydrogen storage together with methane. It is shown that without controlled injection of water, both at the stage of creating the storage and at the stage of storing hydrogen, it is not possible to ensure its subsequent sufficiently complete production to the surface in a reasonable time with technologically justified costs. Otherwise hydrogen reserves are being scattered due to gas migration over very large distances from gas injection wells. Strong influence of the aquifer system parameters associated with the target reservoir is illustrated for dynamics of hydrogen propagation.

Seismic tomography is one of the main tools for obtaining a depth velocity model. Its result largely determines the estimated geometry of oil and gas reservoir. Tomography is a deterministic procedure and does not provide an opportunity to assess the reliability of the results. However, in fact these results directly affect the subsequent economic decisions. For this reason, the aim of the current work is to develop a method of multivariate tomography which allows to determine the reliability of the results. The paper considers several factors of multivariance. Factor of input data quality is generally considered and stochastic averages tool is proposed for estimating input data reliability. Typically, input data estimation involves calculating supergathers. Usage of equivalent weights for supergathers accumulation means that all gathers have an equivalent quality but in practice this is far from the truth due to various regular noises. Replacing weights by random ones is equivalent to filtering with random kernel. These means assigning a random confidence levels to input gathers. This allows to generate many realizations of the input data for inverse problem. Also incorporation of tomography smoothness parameters variation to inverse problem is proposed. Such approach differs from traditional ones where these parameters are set by a specialist based on purely personal ideas. All together this allows to generate many realizations of depth velocity model and estimate its reliability. The proposed method of multivariate tomography doesn't use the known statistical distributions of the input data errors, thus, it is the most general and realistic. Its result can be utilized in the assessment of economic risks.

Today's oil & gas industry faces a number of different challenges. Drilling activities are ramping up due to an increase in hydrocarbon demand combined with a reduction of easy-to-recover reserves. Horizontal drilling is growing and has become an integral part of field development. The geology is becoming more and more complex requiring drilling through dense layers targeting thin-layered reservoirs with lateral changes and anisotropy. In recent years, companies have been looking at the ways of optimizing drilling costs by increasing efficiency and process automation. This has been a driver for many companies to stay profitable and efficient in the market. One of the areas of interest for process automation has been a geosteering. Geosteering is the real-time adjustment well trajectory while drilling to maximize effective footage in the target zone. In this paper, innovative new approaches to automation of the geosteering process will be discussed. This approach has been successfully tested and deployed in several leading O&G companies. The main objective of automated geosteering is to optimize horizontal well placement while freeing up time operational geologists had spent doing routine work in order to focus on complex and more intense tasks as well as the reduction of operational errors related to human factors. This paper will provide details on several automated geosteering algorithms. They have been tested successfully on large numbers of wells. The results of automated geosteering were as close as 90% to the manual interpretations done by geologists. When the results diverged, the geologists often "agreed" with the interpretation proposed by the algorithm.

The composition and properties of oil change during its flow through the reservoir, which is associated with the high molecular weight resins and asphaltenes retained in the pores. Oil is retained in the thinnest capillaries and narrow contacts of hydrophilic mineral grains (capillary-retained oil) and as a film on the surface of hydrophobic minerals (oil films). To confirm this, core analysis tests were performed on three pre-prepared core columns made up of standard core samples with different porosity ϕ , absolute permeability k , irreducible water saturation S wir and other properties. Oil was flowing through the column and displaced by water with pre-determined physical properties. The properties of the core specimens, oil and water, as well as the thermobaric conditions of flow experiments were selected so that they corresponded to the reservoir conditions of the Pashian horizon of the Romashkinskoye oilfield of the Republic of Tatarstan. In the case of the mature Romashkinskoye oilfield, the relevant objective is to quantify and localize the remaining reserves of capillary-retained oil and oil films and substantiate effective technologies for their extraction. To prove that the composition of oil change during flow through porous media, the light absorption coefficient of oil k la was investigated that depends on the relative content of resins and asphaltenes in the oil. Oil was studied using a photometer in a continuous mode during the entire period of oil displacement test. Oil samples were collected and subjected to preparation at the inlet and outlet of the core column, their optical density D, light absorption and transmission coefficients were measured in vitro, and statistical data were processed. It has been found that regular changes in the oil k la occur both at the stage of the core column saturation with oil (a regular decrease), and as oil is displaced from the core samples by water (a regular increase). The identified patterns are the function of the rock and oil properties, the established rate of the column saturation with oil and oil displacement by water, and the amount of residual and displaced oil. The obtained data have shown the promising outlook for continuing laboratory experiments to study not only changes in the properties of oil when it is displaced by water, simulating the development processes, but also those occurring in the column as it is saturated with oil, simulating the processes of primary migration and accumulation of oil in a natural reservoir.

Currently, one of the most widely used methods of extracting hard-to-recover oil reserves in Russia is drilling horizontal wells. Support for drilling horizontal boreholes is based on a 2D geonavigation section using LWD and MWD data, without taking into account 3D seismic data. In the conditions of development of deposits with hard-to-recover reserves, which have a large number of disjunctive violations and geological uncertainties, there is a need for operational use of 2D and 3D seismic data as a method of increasing the efficiency of geonavigation. Specialists of the Department of geological support for drilling Of the branch of LLC LUKOIL-Engineering" VolgogradNIPImorneft " in Volgograd have developed a method for using seismic data in the operational mode in the process of geonavigation. The method was tested on the example of drilling and drilled wells and the analysis of the obtained material was carried out, the efficiency of using this method was determined.

In the framework of the contract with the Ministry of Education 2010-2012, TNG-Group andKazan Federal University developed a mobile YaMR-Kern unit to acquire information on filtration-capacitive properties of full-sized freshly drilled and extracted core samples, to estimate porosity, to determine free and bound fluids, permeability, residual water saturation, to assess the nature of saturation by analyzing the two-dimensional distribution of relaxation times and diffusion coefficient directly at the wellsite without preliminary core preparation for studies. Efficiency of the unit was tested on more than 1600 m of full-sized core samples taken from sediments of various ages and saturated with oils of various viscosity grades. The core study directly at the wellsite, that is, immediately after its extraction to the surface, allows not to lose the very first information about the studied object as soon as possible, since the study of the core drying process showed that during the first hours the core loses up to a third of fluid-saturated porosity, and 20 days later dries out almost completely. Scanning the NMR properties of the core is carried out with high detail, every 1-2 cm, and does not involve any preparatory work, that is, the core does not break down and can later be used for laboratory studies of both full-sized core and standard samples. Such information is extremely important at the stage of exploratory drilling on poorly studied survey targets, as well as in the study of a thin-layered section of wells.

Wrong manual interpretation from the log data about the formation type and other important information can be catastrophic for the company-operator. With Machine-Learning (ML) (a branch of Artificial Intelligence) algorithms, the interpretation of formation type from the log data has been addressed. As a result, we have successfully developed a program able to accurately predict the type of formation. Using the conventional Machine Learning technique of splitting the data into training, validation and test sets, we tried six different ML algorithms to fit with the training part of the data and then verify their prediction accuracy with cross-validation scores and cross-validation predictions which tests the performance of the classifiers (ML algorithms) on the validation set. The three best performing classifiers were selected and further improved by a search of classifier's best hyperparameters. These improved classifiers are further tested on unseen data to produce a comparative analysis. Our prediction accuracy with Receiver Operating Characteristic (ROC) scores and ROC-Area Under-the-Curve (ROC-AUC) for each type of formation from the log data lies in the range of 95-99%, except for formations such as shaly sandstone and shale (50% and 84% respectively). The reason for this seemed to be under-fitting i.e., during the training, the classifiers did not see enough instances of these types of formation to know exactly what characteristics of the data make the type of formation to be shaly sandstone or shale. The issue of under-fitting was verified by skimming through the data. To resolve this problem, we suggest training classifiers with a larger data with more targets (types of formation). Furthermore, during the data cleaning (prior to classifier training) and data analysis phases we have discovered important relationships between well logs and defined relative importance of each well log for different formations. This observation can be investigated further to help eliminate the use of multiple well logs while dealing with some formations (based on prior geological knowledge) and reduce the cost of the well logging operations. Using our program with a larger well log data consisting of more formation type instances, we can train the classifiers to accurately predict the formation type irrespectively of differences in formation type. Our program is dynamic in the sense that with different targets, i.e., type of formation fluid instead of type of formation or both together, it can successfully predict either or both targets. Increasing the numbers of data instances resulted in a better training and thus, more accurate predictions. Utilization of the program will make the formation-evaluation process easier, faster, automated and more-precise.

Puguang is the biggest sour gas field in China with 17% H 2 S and 9% CO 2 concentration and is the major gas sources for the pipeline from Sichuan to Shanghai. It's important to keep the gas wells healthily and steadily producing. However, the production is continually declining due to water coning, scale buildup and formation pressure dropping. It's urgent to perform well intervention effectively and economically to increase the well production. Production logging in multiple wells identified that inflow zones were less than 30% of perforation interval because of formation invasion and perforation tunnel plugging from initial completion. To release the potential productivity from nonproducing zones, reopening the perforations is critical to reverse the trend of production decline. To pass through the 3.5-in tubing with minimal restriction of 2.7-in and to effectively perforate the 7-in production casing and the carbonate formation, a 2.5-in spiral-exposed perforation system was finally selected as the optimized solution that can achieve the deepest formation penetration compared with conventional carrier system from simulations with rock-based perforation model. The spiral-exposed perforation system was modified to be H 2 S resistant, and wellbore dynamic simulation was conducted to minimize the gun shock to avoid gun drop during detonation. The detailed job design and risk mitigation plan were made as well to avoid any failure in such a highly corrosive environment with well depth up to 6,000 m. The first reperforation job was conducted successfully, and the well production increased 130,000 m 3 /day or 22.8%, and afterward, production logging confirmed that zonal production had significantly improved from the newly perforated interval. Then another seven wells were reperforated with an interval of 30 m to 45 m and average 100,000 m 3 /day gas production increment or 20% per well was achieved. It's proven that reperforation with redesigned exposed perforation system is the effective and economical way to increase production in the Puguang gas field. This paper illustrates how and what we do for exposed system improvement, candidate well selection, planning, and executing the through-tubing exposed perforation in such extremely challenging conditions. It also discusses lessons learnt and recommendations for future well intervention to steadily increase the well production in the Puguang gas field.

The digital core analysis technology with direct hydrodynamic modeling based on the density functional method was applied for the first time for the EOR screening and evaluation of the EOR agent efficiency at pore scale for Achimov reservoir rocks. The technology consists of scanning core samples by X-ray microtomography (microCT), constructing the corresponding digital core models of the pore space geometry, and performing multiphase hydrodynamic modelling at the pore scale based on the density functional method (DFT). The required spatial resolution of digital models for the studied sample was about 1 μm, and the size of the representative elementary volume on which multiphase hydrodynamic modeling was performed was 750 × 750 × 750 voxels. Despite the extremely low permeability values (less than 1 mD) of the test sample, digital core analysis allowed a series of digital experiments to calculate the absolute permeability, the creation of residual water saturation using different approaches (simulation of the laboratory protocol and geological process) and the determination of oil displacement when injecting various EOR agents (formation water, carbon dioxide and smart water). For the first time, the dependence of the displacement coefficient both on the method of modeling the initial conditions (residual water saturation) and on the type and mechanism of the considered EOR agents for Achimov reservoir rocks was studied.

We present a new effective method for the acoustic wave modeling in transversely isotropic media with the tilted axis of symmetry. It makes novel accurate techniques of migration, such as Reverse Time Migration (RTM), computationally affordable in terms of memory usage and speed. Our modeling is based on pure acoustic wave equation derived from the fundamental physical laws – Hooke's law and the equation of motion. There is no need to approximate the pseudodifferential operator for the decomposition motivation in our approach, which was the primary problem in solving the acoustic wave equation. First, we perform the rotation of the operator in the spectral domain in accordance with the parameters of the tilted transversely isotropic (TTI) media. Next, we make a discrete inverse Fourier transform of the desired frequency response contained in the pseudodifferential operator to build the corresponding spatial operator and, finally, truncate the operator with a window to reduce edge effects. As a result, the obtained spatial TTI operator is applied locally to the wavefield through a simple convolution. Taking advantage of fast convolution algorithms, this equation can be efficiently solved, resulting in an explicit numerical scheme. There is no need to deal with the implicit schemes resulting from various approximations of the pseudodifferential operator with our method. It greatly facilitates the calculations for the full modeling. The most significant advantage of our approach lies in its locality, which means that our spatial TTI operator can be implemented in any selected area individually. Our approach can be combined with classical fast finite-difference schemes, e.g. when the media are isotropic and elliptical. Also, the modeling is performed without generating any spurious modes, which greatly reduces the total computational time and memory usage as well as improves the quality of seismic image. We demonstrate the stability, accuracy, and the absence of the residual S-wave artifacts with several numerical modeling examples including complex heterogeneous case.

The choice of the optimal trajectory of horizontal and directional wells, the placement of frac-ports for multistage hydraulic fracturing, taking into account prepared input data (using geological and geomechanical modeling with the rock properties anisotropy), provide optimization of hydraulic fracturing operations and field development. Formation T contains more than 3 trillion m 3 of gas, and is already an object of close attention of the largest oil and gas companies. The unique character of the object is due to the high reservoir compartmentalization of the collector and low permeability. Therefore, the main development strategy for the reservoir is to drill low-angle and horizontal wells, followed by multistage hydraulic fracturing. The main goal of multistage hydraulic fracturing is to join productive intervals and at the same time avoid undesirable fracture breaks into neighboring layers. To achieve this goal, several tasks were solved: creation of a petrophysical and geological basis for geomechanical modeling, creation 1D and 3D geomechanical models taking into account the rock properties anisotropy due to the high layering of the reservoir, and preparing input data for hydraulic fracturing design. For the qualitative creation of the geomechanical model at the observation wells of the field, an expanded complex of special well logging studies has been performed, borehole measurements of reservoir pressure and minimum horizontal stress have been carried out according to the results of stress tests, core sampling and research to determine petrophysical and mechanical properties. The analysis of the obtained information revealed the features of the stress state along the section and reservoir area, which were taken into account in the design of hydraulic fracturing. Geomechanical modeling was carried out in a uniform work procedure, which made it possible to unify the result, improve the quality of calculations and forecast parameters for horizontal wells.

Constant growth of commercial hydrocarbon (HC) consumption requires for the oil and gas industry to be involved into exploitation of unusual oil and gas reserves, preventing HC supply shortage on the global market. The fields with conventional reservoirs being actively developed during the last century have a tendency now to reduction of routine parameters of HC production. Now more and more attention is being attracted to tight reserves, which have to be studied in unconventional ways. This article focuses precisely on complex reservoirs, in which reserves are classified as tight. A complex quantitative assessment using several different technologies for long-term monitoring under difficult conditions has shown favorable results.