The effectiveness of exploration and subsequent production drilling and resource base assessment is determined by the reliability of the geological model of the field, the quality of which depends on the most likely distribution of parameters in the inter-well space of the deposit and the most accurate determination of water-oil contact (WOC). The position of the WOC and the size of the transition zone are key parameters for evaluating the field's reserves, determining the depth of well hole targets, and monitoring the development of the field. The purpose of this work was to determine the free water level (FWL), the size of the transition zone and WOC position on the basis of a integrated approach that takes into account well log interpretation data, capillarometric studies, well tests, results of hydrodynamic logging, production logging test (PLT) and well operation in the carbonate deposits of a complex lithofacial structure of a unique field in the South of Iraq.

Automated pay zone detection on well log data using machine learning Nowadays in the oil and gas industry more and more tasks are related to the analysis of big volume of data. Successful solutions to this type of problem are based on machine learning algorithms. The aim of this study is to create an automated model for predicting pay zones based on the analysis of well log data. The object of research are sedimentary deposits of the BV10 object of the Samotlorskoe oil and gas condensate field. In this project an approach for the gradual interpretation of lithotypes, prediction of the saturation type for potential reservoirs and also the prediction of porosity and permeability was chosen. The article discusses the application of three machine-learning algorithms: the support vector machine method, the neural network and the random forest algorithm. The existing problems of the studied data are described as well as methods for solving them and the stages of data preparation. As a result of the analysis it was decided to use a neural network to create a model for predicting pay intervals. Additionally, the accuracy of the model predictions was estimated from two wells excluded from the analysis.

The complex interbedded heterogeneous reservoirs of the Severo-Komsomolskoye field are developed by horizontal wells in which, as part of the pilot project's scope, autonomous inflow control devices (AICD) are installed to prevent early coning and gas breakthroughs in long horizontal sections and reduce sand production, which is a problem aggravated by an extremely low mechanical strength of the terrigenous deposits occurring in the Pokur formation of the Cenomanian stage in this area. The zones produced through AICDs are separated by swell packers. The issue of AICD effectiveness is discussed in the publications by Solovyev (2019) , Shestov (2015) , Byakov (2019) and some others. One of the methods used for monitoring horizontal sections with AICDs is production logging (PLT). However, due to the complexity of logging objectives, the use of conventional logging techniques makes the PLT unfeasible, considering the costs of preparing and carrying out the downhole operations. This paper provides some case studies of the Through-Barrier Diagnostics application, including passive spectral acoustics (spectral acoustic logging) and thermohydrodynamic modelling for the purpose of effective estimation of reservoir flows behind the liner with AICDs installed and well integrity diagnostics. As a result of the performed diagnostics, the well completion strategy was updated and optimised according to the log interpretation results, and one well intervention involving a cement squeeze with a straddle-packer assembly was carried out.

The structure and composition of oil reserves deteriorate in the course of a mature oil field development due to geological and technological factors. The geological factors include vertical and lateral macro-and micro-heterogeneity of the reservoirs under development. At the same time, macro-heterogeneity leads to the formation of bypassed residual oil in low- permeability and stagnant layers, zones and lenses that are not exposed to stimulation, while micro-heterogeneity contributes to the formation of residual reserves of capillary oil and oil films. Technological factors include impossibility to fully account for reservoir heterogeneity when substantiating well spacing, pressure gradient, or flooding technology. The key problem here is the lack of clear understanding of the distribution pattern, quantity and deterioration of the quality of residual oil in water-flooded reservoirs, which makes it challenging to reasonably select a technology for effective oil extraction. Despite the improvements constantly made to the production logging, hydrodynamic and interpretive, seismic, lithofacies and other methods of exploration and residual reserves modeling, it is often impossible to obtain timely reliable information about the percentage of reserves depletion and their coverage with the development activities. This paper proposes another method — optical — that, in combination with well logging and hydrodynamic surveys as well as geological and hydrodynamic simulation, has been tested to assess the quantity and spatial pattern of residual oil reserves of the Kynovian ( D o ) and Pashian ( D 1 ) horizons at the experimental site of the Romashkinskoye oil field (Devonian formation). From the theoretical and methodological standpoint, this method is underlain by the results of in vitro studies of core columns and involves the selection and research of optical properties of oil wellhead samples, mathematical processing and correlation of the obtained optical and field data. The obtained estimate of residual reserves is compared with data derived from geological simulation, the most promising automated method for identifying, geometrizing and calculating residual recoverable oil reserves ( RROR ). The proposed method offers such advantages as ease of use, promptness, reliability, functionality and cost-effectiveness. It uses actual data on cumulative well production and takes into account the current reservoir and fluid porosity and permeability ( P&P ), which provides the possibility to obtain more precise estimates of the RROR quantity and spatial pattern.

The main objectives of field development are to maintain high profitability, as well as to achieve the highest coefficient of oil recovery (COR). One of the ways to ensure a high COR for oil fields is creation of a reservoir pressure decrease system (RPD). So, for example, when create a system of RPD, the COR can reach 0.5 d. q., and without RPD - only 0.1-0.2 d. q In the case of designing the development of oil fields with a complex geological structure (the presence of a gas cap, block structure of the Deposit, a large number of faults), the complexity of the task of choosing the optimal development system increases significantly. In Russia and in the world, there are a considerable number of oil fields that have been developed for a long time on the depletion mode, which has led to the formation of a considerable volume of the free gas phase. Such deposits often pass into the category of problematic and are characterized by low current values of the coefficient of oil recovery (COR), as well as the lack of reliable technological solutions for their effective development. Examples include the Talinsky area of the Krasnoleninsky field, the oil pool in the Jurassic sediments of the Novogodnee Deposit, and others. When the pressure increases further, for example, by pumping water, modeling the development of such deposits requires the use of non-equilibrium hydrodynamic models. Application of the results of the pressure interference test (PIT) allows us to obtain valuable information about the connectivity of inter-well intervals, a quantitative assessment of the conductivity of reservoir faults, and, consequently, reduce risks when planning field development, increase the efficiency of ongoing geological and technical measures and their profitability. Conducting of PIT on a working stock, in comparison with classical methods, allows you to minimize the loss of production during research. Proper planning of field development with the involvement of PIT results, in particular-the introduction of the RPD system, allows to increase the COR and profitability of the development system as a whole. The paper shows the results of the pressure interference test studies for a tectonically complicated structure of an oil and gas condensate field. Based on the results of the research, the efficiency of the existing RPD system was evaluated and decisions were made to transfer production wells to injection, taking into account the assessment of the risks of water breaks through conducting faults. In addition, the results of the pressure interference test were combined with the results of tracer studies. The convergence of research results by both methods is shown.

Development of oil rims at oil-gas-condensate fields is accompanied by a high risk of gas coning which leads to well productivity losses followed by conversion of such wells to an idle stock. In order to increase the oil recovery factor of oil rims and to eliminate early gas breakthroughs, horizontal wells drilled in thin oil rims are equipped with autonomous inflow control system. The study describes the experience of AICD application for one of the largest fields in East Siberia with an oil rim and a large gas cap, where an integrated analysis of the AICD well performance was conducted for the first time in Russia. This analysis includes: choosing well-candidates, performing AICD lab testing, sector reservoir simulation, modeling of AICD effect, followed by the actual well performance analysis after running AICDs. All this became possible due to the well-organized cooperative work of the operator and the contractor. The wells included in this study were successfully put into production at lower GOR values compared to their surrounding wells

The article presents the projected results of the offshore development option in the zone of deteriorated filtration-capacitance properties. To involve additional oil reserves in the development, it is proposed to use multi-stage hydraulic fracturing technology at the projected horizontal wells. The analysis was executed using modern methods of geological, hydrodynamic and geomechanical modeling. Method of most favorable zones’ isolation for carrying out multi-stage hydraulic fracturing of formation based on maps of permeability, current formation pressure, density of residual movable oil reserves and cover power is proposed. Taking into account the selected zones and the expected direction of crack development, the trajectories of new horizontal wells with a large deviation from the vertical were optimized. Efficiency assessment was carried out by comparing the technical and economic parameters of the proposed development option (horizontal wells with multi-stage hydraulic fracturing of the formation) with the basic version (horizontal wells with traditional completion). A hydrodynamic model was used to calculate oil production levels according to options. As a result, it was proved that the use of multi-stage hydraulic fracturing technology will involve additional oil reserves in the development and increase the efficiency of expensive offshore drilling.

The paper reports on the procedures of selection and evaluation of surfactant-polymer composition to improve the development efficiency of Kharyaga field D 3 -III carbonate formation. The main goal was to establish an efficient chemical composition that could significantly improve oil recovery factor and are compatible with high salinity formation (up to 170 g/l) and injected water (60-80 g/l) at formation temperature 62°C. Laboratory results include the composition screening and core flood experiments on analogous carbonate cores; the best prospective scheme of injection is validated. A physico-chemical model of oil displacement at negative salinity gradient is validated with technical calculations. Additional laboratory program is currently planned for validation of uncertainty parameters. It includes displacement of oil by surfactant and polymer solutions on Kharyaga field cores and evaluation of dynamic adsorption of chemicals.

As the production of hydrocarbons from the carbonate reservoir increases, there is a necessity to enhance oil recovery methods to increase recovery factors and improve the economic efficiency of field development. The knowledge of wettability's role and fluid distribution at the pore scale is required to comprehend the mechanisms for oil displacement from porous media. The X-ray computed micro-CT technology provides opportunities to study the complex fluid displacement process at the pore level. This work discusses wettability restoration in carbonate cores and its effect on fluid distribution in porous space. Wettability restoration refers to restoring the original wettability of the core after extraction. We investigate wettability change and two-phase fluid distribution at pore-scale with the help of micro-CT technique along with Amott spontaneous imbibition methods. The Amott spontaneous imbibition experiments performed on the core under ambient pressure. The micro-CT experiments conducted for steady flow core flooding experiments on harsh cleaned cores. The three-dimensional images acquired for dry core, core saturated with brine and kerosene followed by oil injection. For better visualization of the fluid-fluid and fluid-rock surface and to remove voxel artifacts, iodo-octane is mixed with oil with 10 % wt/wt. The experiments allow us to envisage the structures of fluid in each phase during the displacement of fluid in carbonate rocks with high resolution (3 μm/voxel). The novelty of this approach lies in efficiently capturing the CT images of the fluid distribution and its influence on wettability during the "core-aging" procedure and validating the results of it with the Amott imbibition wettability index. The initial wettability of harsh cleaned carbonate cores was identified as water-wet compare to mixed wettability for mild cleaned carbonates. Nevertheless, all the samples become strongly oil-wet regardless of the cleaning methods after long-term saturation with crude oil. The X-ray CT technique revealed the fast evolution of contact angle of brine corresponding the wettability changes to strong oil-wet after contact with crude oil under the reservoir conditions.

The issue of increasing reservoirs recovery rate in non-uniform permeable high-viscosity oil reservoirs is considerably challenging, especially when the oil under reservoir conditions manifests its structural-mechanical properties, which is characteristic of the Buzachi North oil field. Its development using water flooding method has demonstrated that even moderate uptake of recoverable reserves is followed by injection water breakthrough to the production wells. As substantiated by the high median permeability quotient with a broad range of values, employment of a regular ("classical") polymer flooding technique for the task of aligning the oil displacement front, when instead of water a weak polymer solution is injected in high volumes (up to 30 % of pore volume), is of similarly low efficiency because of rapid polymer breakthrough to the production wells boreholes through fissures and "super reservoirs". This article presents development and field pilot tests results related to cyclical gel polymer flooding technology as applied under the conditions of the Buzachi North oil field productive reservoirs rich in high-viscosity oils. The technology implies an integral gel polymer action upon water-bearing strata of productive reservoirs via injection wells performed in several stages. During the first stage, fissures are isolated with water-swellable polymers or synthetic resins; during the second stage, profile log is aligned using high-viscosity hydrogels; finally, during the third stage, the oil is displaced with a low-viscosity hydrogel slug based on cross-linked acrylamide polymer. Based on laboratory and field research, optimal linear dimensions (fractions) of water-swellable resins have been selected, along with cross-linkers and their concentrations required to obtain high-viscosity gels under reservoir conditions; the optimal amounts of low-viscosity hydrogels to be injected at the displacement stage have been determined. The parameters of fissures and "super reservoirs" required for estimating the working amounts of injected gels at each stage are evaluated by means of tracer analysis performed immediately prior to the injection cycle start. The tests performed at 16 sites with Jurassic deposits and two sites with Cretaceous deposits of the Buzachi North oil field have demonstrated high technical and economic efficiency of the developed cyclic gel polymer flooding technology.

We evaluated the performance of a field-wide post-steam in-situ combustion (ISC) project conducted in a complex heavy oil reservoir in China using laboratory one-dimensional combustion experiments, reservoir simulation outputs, and data collected from the field application. The commercial ISC project showed vastly different production performances in different regions of the field and two types of representative well groups were identified. Type I group has a low oil viscosity (<8000 mPa.s) and a high steam-flooded recovery factor (>30%); after ISC treatment, these producers show a high initial water cut, while some experience channeling issues and hence produce a large quantity of flue gas. Type II group has a high oil viscosity (>20000 mPa.s) and a low cyclic steam stimulation (CSS) recovery factor (15-20%); these producers have a high air injection pressure exceeding the fracture pressure. Corresponding remedial methods were designed and applied to these two well groups. Presently, the evaluation methods described in this paper are being applied in the field, and initial results have been acquired.

The aim of this work is to develop an approach to multivariate optimization of development systems for tight oil reservoirs of the Achimov formation, where large volume of drilling of RN-Yuganskneftegaz LLC are currently concentrated on. The approach described in the paper is an integral part of the corporate module "Decision Support System for drilling out new sections of tight oil reservoirs", which allows making quick design decisions for new drilling sites of target objects. The main factors that reduce the development efficiency of such objects, in particular with the use of water flooding methods, are the low piezoconductivity and high heterogeneity of a reservoir that leads to relatively high rates of decline in fluid production and, in particular, to long response productivity time for production wells to injection. In this paper, we consider a multi-criteria assessment of the effectiveness of various well placement systems in various conditions that characterize the geological features of tight oil reservoirs and low-connected reservoirs. A specific example is considered - tight oil heterogeneous reservoir of the northern part of Priobskoye field, for which oil production is calculated by numerical hydrodynamic modeling methods. As a result of development and testing of the approach: Main geological and technological parameters are estimated that affect development indicators and empirical dependencies derivation (of the development indicators) on the geological features of the selected clusters of Priobskoye field target objects; A method being proposed for description of a various geological features of the reservoirs of Achimov formation target objects by using synthetic stochastic 3D geological models; A physically-meaningful approach is proposed for adaption of well dynamics that reveal tight oil reservoirs of target objects using synthetic 3D geological and hydrodynamic models. Based on the actual data of development (well operation), formation parameters are determined for each cluster (section) of the target objects of Priobskoye field, which differ in geological features and development indicators; Prediction multivariate numerical calculations were carried out for various well placement systems under various geological conditions (≈ 3 million calculations). A database of calculated development indicators has been formed for each variation of the well placement system; Different options are presented for visualization of calculation results in the form of dimensional templates of optimal development systems for tight oil reservoirs; Various options for sensitivity analysis visualization for the effectiveness assessment are presented of various well placement systems to changes in geological, technological and scenario conditions.

In recent years, microbial enhanced oil recovery methods have been systematically applied in the Daqing oilfield in order to stimulate and increase oil production, remaining difficult to be recovered after polymer flooding. In this paper, a selection method of activator for indigenous energized microorganisms in Daqing oilfield with low permeability reservoirs was proposed. Firstly, the number of microorganisms in samples taken from production and injection wells in the target block was measured. Based on the obtained results, the condition for the use of MEOR method in the studied well system was determined. Secondly, laboratory experiments were conducted on the culture of indigenous microorganisms and the optimal parameters of the activator for indigenous microorganisms was determined by the obtained experiment results. Thirdly, the concentration of indigenous microorganisms, the pH value, interfacial tension, the viscosity change of the crude oil and the amount of generated gas after the hydrocarbons metabolization were measured. Based on the values of the crude oil viscosity and the amount of generated gas, the optimal ratio of nutrients (glucose and corn steep liquor) that are part of the activator for indigenous microorganisms was determined. The experimental results showed that when the ratio of nutrients (glucose and corn liquor) is equal to 1:2, the viscosity of the crude oil after the activation is minimal and the amount of generated gas after the hydrocarbons metabolization reaches the maximum value. The selected activator composition was used to culture indigenous microorganisms in samples taken from production wells in the studied well system. The pressure increase was observed due to the occurrence of biogas during the process of hydrocarbon degradation by microorganisms. In the further development of the Daqing field with low permeability reservoirs using microbiological methods, it is recommended to use the selected activator composition for the culture of indigenous microorganisms.

Heterogeneity is the basic characteristic of reservoir, which seriously affects the overall development effect of oilfield. In order to solve this problem, a new flooding system, soft microgel, has been developed in recent years. Its field test has obtained obvious effect of increasing oil and decreasing water. However, the research on its reservoir adaptability and displacement mechanism are still in the initial stage. Therefore, this paper has carried out relevant research work and introduced the field test results. Soft microgel particle dispersion is a heterogeneous system, composing of microgel particles and carrier fluid. In this paper, the microfluidic technology was used to simulate the particle separation phenomenon in the migration process of soft microgels. Guided by the theory of red blood cells in biological fluid mechanics, a mathematical model of concentration distribution of soft microgels in different channels was established. Furthermore, in order to explore its oil displacement mechanism and performance, micro and macro physical simulation experiments were carried out. Finally, its typical field application is introduced. Results show that, the separation phenomenon between soft microgel particles and carrier fluid occurs when injecting into the core. That is, soft microgel particles first enter the larger channel with low seepage resistance, while fluid turns into the smaller channel to displace oil. Therefore, by the cooperation between microgel particles and carrier fluid, soft microgel particle dispersion can effectively expand sweep volume. Furthermore, soft microgel particles can migrate, be trapped, deform in the porous medium. Based on the resistance coefficient, residual resistance coefficient and plugging rate, the migration and plugging modes of soft microgels can be divided into 3 modes: efficient plugging, normal plugging and low efficiency plugging. In the normal plugging mode, soft microgels can not only adjust the profile effectively in the early stage of injection, but also migrate to the deep reservoir and improve the injection pressure. Also, 3D macroscopic physical simulation experiments show that soft microgels can moderately plug the high permeability layer and improve the displacement effect of low permeability layer, which finally achieve the goal of enhanced oil recovery. Furthermore, soft microgel particle dispersion has been applied in 8 different reservoirs, and has achieved remarkable effect of increasing oil. Taking JX6ZD as an example, the daily oil production in the pilot test area increased from 25t/d to 75t/d, and the water content decreased by 38%. Therefore, through the lab physical simulation and field tests, the progressiveness of soft microgel particle dispersion can be proved. In this paper, the mechanism and performance of soft microgel particle dispersion are studied by a multidisciplinary approach. On this basis, the field test results are analyzed. The above research results provide theoretical basis and technical support for the popularization and application of soft microgel particle dispersion system.

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

Most of the Russian oil fields consist of the complex reservoirs and it is required to apply secondary reservoir development methods, such as waterflooding, in order to increase reservoir development efficiency. However, for highly heterogeneous reservoir with viscous oil, "classical" waterflooding is not enough and there is a need to use enhanced oil recovery methods, one of which is polymer flooding. The prospects polymer solutions injection have been proved in different fields worldwide, including the East-Messoyakhskoye field at the PK1-3 reservoir with high-viscosity oil. At this field, polymer flooding pilots were carried out and taking into account the obtained field data, the geological and dynamic model were updated, which helped to improve the process physics understanding and evaluate the possibility of sweep efficiency increase during project implementation. This paper describes the challenges, difficulties, applied approaches, results and experience obtained in reservoir simulation of polymer flooding.

A case study is presented discussing a specific completion strategy applied in the Daqing oil field, Block Long26, and the outskirts of tight oil wells. An alternative fracture completion method and enhanced flowback technology were used to develop these tight oil fields. The methodology applied resulted in improved efficiency of the fracture completion strategy and post-stimulation flowback, which reduced operational time and related costs. Optimized fracture cluster spacing length was determined based on the operational time efficiency and engineered fracture completion design. Laboratory testing was performed to select fluid recipes, and field trials were performed for the correlated custom-made microemulsion technology, which enhanced post-fracture flowback to shorten operational time and increase the return on investment ratio and production. Field results and post-fracture completion production are promising. Several post-fracture completion production surveys have been applied in the Daqing field, Block Long26. The most popular completion strategy applied in this field involves using less than three perforation clusters in each fracture stage, applied using multiple, horizontal fracture stages, with longer and (normally) much greater fracture spacing length, thus requiring less fracture cluster treatments along the horizontal laterals. After stimulation, normally, additional days are necessary to observe the oil drop showing; thus, alternative flowback technology is necessary to enhance post-stimulation flowback to help improve the return on investment ratio. Limited entry fracture and/or extreme limited entry fracture technology were part of the intensive fracture cluster completion strategy to benefit fracture completion and production. Field operations involved doubling the current perforation and fracture clusters in one fracture stage. Laboratory methods were used to select the appropriate mircoemulsion additives to form a fracturing fluid recipe to aid oil production and enhance flowback.

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.

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.

It is shown that hydrophilic (inhibitor) and hydrophobic (hydrophobizing) compositions are able to increase the permeability of the bottom-hole zone of the clay Turonian formation and prevent the formation (and, if necessary, destroy) gas hydrates in the bottom-hole zone of the formation. Hydrophilic and hydrophobic compositions contain solvents (methanol or petroleum ether) that are easily removed by the gas flow, and active non-volatile components (ABR or magnesium chloride) that remain in the formation. The use of "active substance + volatile solvent" compositions allows to have a long-term effect on the reservoir Bottom-hole formation zone (BHFZ) and easily remove liquids from the gas formation by gas flow. The use of hydrophobic compositions and fluids is promising in the production of oil and gas from clay reservoirs (Cenomanian, Turon, Senon, Bazhenov and Tyumen formations, etc.).