The aim of this work is to create a tool that can help in making difficult investment decisions about the sequence and commissioning periods of new hydrocarbons fields, maximizing expected monetary value and considering infrastructure constraints across a group of assets in terms geological uncertainties. The approach is to use probabilistic calculations and the modern portfolio theory, adapted to the conditions of the sphere of petroleum exploration and production. The goal of optimization is finding a strategy for new assets development that would have the maximum profit with minimal economic or technological risk. Measures of spread of a random variable (a.g. NPV) around its expected value are used to measure an economic risk. Also, we propose a method of technological risk assessment, reflecting the probability of hydrocarbon production in the required range. To obtain a probability distribution of the objective function according to uncertainties in input data the stochastic Monte-Carlo simulation and "Latin hypercube" technique were used. Due to high dimensionality of the problem, heuristic optimization methods have been used to solve the optimization task. A proxy model, based on the change in recoverable reserves volumes, starting production rates and decline rates of hydrocarbon production for newly drilled wells is proposed in this paper. The model combined with the calculation of economic measures. The combination of simulation models with an optimization algorithm allows to analyze a set of mathematical equations, containing a number of decision variables (e.g., years of commissioning periods and/or the paces of drilling wells) and to determine their optimum values, leading to a solution with the desired ratios of the expected economic effect and risk value. As a result, the numerical experiment revealed that application of the portfolio optimization methods allows to find new non-obvious solutions. The result of portfolio analysis is not a final product of project works, but, however, may be a basis for explanation of optimal development scenarios for a group of assets and can help in finding non-obvious, but more effective investment and project decisions. A comparison of four heuristic algorithms in the single-criterion optimization problem was conducted. Conclusions about the effectiveness of the algorithms in terms of time and the fitness function values were made. The developed model and methods were used in task of searching the optimal development strategy for a group of real hydrocarbons fields.

The paper presents the experience of using downhole microseismic monitoring to determine the direction of working agent losses while maintaining formation pressure in Baitugan oil field in Orenburg region. Studies were aimed at history matching and elaboration of the further strategy for formation pressure maintenance (FPM) and field development as a whole. The seismic monitoring method was used in the downhole version, when observations are done from the observation well located nearby the injection one. For reliable recording of weak microseismic events, high sensitivity receivers were used with 4 sensors per component. A special injection program was developed. Its first stage consisted in optimization of modes that ensure the maximum injection into formation of a fluid supplied at the wellhead. During acquisition parameter testing, passive recording of the seismic signal was done at all stages of injection during two weeks in various modes, including a short-term stop of injection with subsequent increase in injection to a maximum injection rate with exceeding the fracture gradient. Fracture growth zones were identified below the target formation. Starting from the second week of recording, fracture propagations to the overlying formations were observed under increased injection pressure. Based on data obtained, a three-dimensional map of microseismic events recorded in the formation was created. It was used for interpretation and allowed to specify geometry of self-induced hydraulic fractures depending on injection modes. Microseismic mapping of self-induced fractures in injection wells was done in Russia for the first time. The results of observations allow to optimize the formation pressure maintenance system through optimizing injection modes depending on local fracture gradients and injection shutting off in the zones with uncontrolled self-induced fractures that develop under minimum wellhead pressures. The obtained data also make it possible to significantly improve quality of history matching for carbonate deposits with reduced formation pressure through determining the injection efficiency. This result directly improves both the quality of forecast analysis and economic impact of formation pressure maintenance.

The biggest part of the Company's asset portfolio consists of mature fields with declining production levels. High water content in produced reservoir fluids, and low production rates become the reason for low economic efficiency of a significant number of production wells that fall into the category of marginal or unprofitable wells. Reducing operating expenses for artificial lift and bringing these wells into the profitable category is the goal of the Technology of Oil Production from Marginal Low-Rate Wells project launched in our Company in April 2017 ( Kibirev E.A. and others, 2018 ).

When operating production oil wells with electric submersible pump units in conditions of high free gas content in the pump, the mode of flowing through the annular (FTA) may occur due to a combination of factors, such as: relatively high pump intake pressure sufficient to maintain self-flowing conditions through annulus, large amount of gas coming to annulus, high degradation of ESP parameters which prevents decreasing BHP and others. The authors of the article have reviewed literary sources, formulated the relevance of the problem of flowing in annular space of artificially lifted wells. The full characteristics of ESP was adapted by the results of flow loop tests with gas-liquid mixture. It made it possible to develop the model of ESP operation under FTA conditions, which was proven on field cases (four examples). Recommendations for FTA mode optimization discussed.

The increase in the count of fields with deteriorating flow properties and, as a result, long nonstationary flow, leads to an increasing spread of periodic lift method. Classic multiphase pipe flow models used by most commercial simulators are not able to account for transient processes occurring during intermittent operation. The purpose of this work is to develop a method for calculating the pressure distribution in the wellbore and pipelines, taking into account the unsteadiness of the multiphase flow, as well as its testing on the example of solving various problems of production management: analysis of bringing wells on to stable production, monitoring and optimization of periodic well performance, analysis of processes during the start-up and shutdown of processing trains of the oil gathering system.

The paper describes an approach to the analysis of the efficiency of water flooding in relation to the development of the oil rim. The ways of optimizing the existing water flooding strategy are shown based on the actual operation of the wells and the forecast based on the hydrodynamic model. The issues of monitoring and control are considered as well as monitoring the operation of injection wells with the aim of subsequent operational decision-making regarding their operating modes.

Flow testing (FT) is an integral part of any field development. Testing results are used to plan well interventions, analyze the current field development state and make up project documents. However, this testing implies significant financial losses caused by incomplete oil recovery due to time-taking well shut-ins for up to several months, which is especially relevant to horizontal wellbores, fractured wells, low-permeability reservoirs. The production analysis method described in this article allows assessing the same set of reservoir and well parameters as that used for the traditional flow testing, but without oil production losses. The method was tested on 95 wells of the LUKOIL-PERM LLC fields. In order to assess the credibility of the obtained reservoir parameters, the authors made a comparison with the pressure build-up (PBU) interpretation results. The good convergence for the key reservoir properties revealed for most wells testifies that the method is promising as a supplement to transient flow testing. The authors developed criteria and determined an area of application for this type of testing for Owner's fields after studying specialized plots, identifying the dependence of results on the quality of input data, as well as assessing the forecast capabilities of the production analysis method.

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.

In order to improve tools for monitoring the reserves recovery and localization at the Gazprom Neft fields, as part of the technological strategy, a technology for geochemical control of reserves recovery has been developed. The use of geochemistry methods in identifying the targeted flow of fluids from a reservoir is based on the difference in fluids’ composition and properties from reservoir to reservoir. According to laboratory experiments, the accuracy of the geochemical predictions of miscibility based on a multiple linear regression model varies from 1 to 8% for oils and condensates, from 6% to 18% for gases, and from 15% to 34% for reservoir water (provided there is no pressure maintenance system in a reservoir). The technology was tested at Priobskoye field of Gazpromneft-Khantos LLC, which jointly operates Zones AS10 and AS12. The pilot program included 5 wells with pre-installed Y-tool assemblies. The advantage of this system is the ability to conduct tests in a well producing in a stable state with induced pressure drawdown. Simultaneous geophysical studies and wellhead sampling for geochemical studies allowed us to confirm matching of the results of dividing the inflow under the conditions of a well draining two or more target zones. The technology for geochemical control of reserves recovery will allow a breakthrough in the study of wellhead fluid samples in the near future, and such information will increase the success rate and information content of field geophysical studies by an order of magnitude. The advantage of the described technology is 100% coverage of the production well stock and the ability to predict miscibility for all types of fluids (oil, gas, and produced water).

Flow and injection profile monitoring in horizontal wells enhances the oil and gas field development efficiency, which is of particular importance when the target reservoirs have a complex geological structure, as is the case with oil-rim reservoirs located below a gas cap. The objective of this paper is to present the results of multi-well diagnostics carried out in order to estimate the flow and injection rates in Yarudey Field wells (Russia) and assess the downhole completion integrity status. When developing oil-rim reservoirs, flow and injection profiles need to be closely monitored so that gas and water breakthroughs along the length of thin beds and fractures could be promptly detected and appropriate remedial jobs planned. This task becomes more challenging in completions where multistage hydraulic fracturing was earlier performed, or the wells were cased with uncemented liners equipped with swell packers. To monitor the reservoir performance, advanced downhole diagnostics was performed in a group of wells in the field, where such reservoir-oriented techniques as passive acoustics and high-precision temperature logging were used. Application of the passive acoustic logging technique helped to identify reservoir flow zones and detect crossflows behind casing. The flow and injection rates were estimated through temperature simulations. Both these techniques were found to be useful, including those instances when the integrity of complex downhole completions was to be assessed. On the whole, the obtained results have proved the effectiveness of supplementing conventional production logging (PLT) with reservoir-oriented techniques.

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

Effective management of field development requires continuous monitoring of the hydrodynamic parameters of the reservoir and wells. One of the sources of such information is the results of interpretation and analysis of well test. The aim of the work is to increase the quantity and quality of well test, which can be achieved by automating their conduct and the operational processing of field data and events at the wells. The present work describes the concept of well testing in real time, the development and implementation methods for searching candidate wells and algorithms for giving expediency estimation for well testing. Implementation of automation of the production process for well test can be divided into several successive stages: searching for wells for well testing, giving expediency estimation of the well test with the issuance of recommendations, making decisions about the well testing, monitoring well testing, completion and interpretation of the well test. Each stage requires a methodological and algorithmic study for all types of well test. Candidate wells are searched by identifying the shutdowns and monitoring wells. Expediency estimation algorithm of well test includes calculating the duration of well test and production and injection losses, checking changes in well operating conditions, analyzing the conditioning of field data, and planned and completed well activities, including previously well tests and intersection with the well test program. Moreover, an analysis of the business processes of well testing showed that all research methods require automation of routine operations of analysis and preparation of field data from sensors of downhole telemetry systems. For this purpose, a service-oriented application for real-time well testing is being developed. The present software allows one to optimize the well test program with the inclusion of unscheduled well test, to increase the number of studies without increasing the losses in production and injection, and to increase the coverage of measurements and the effectiveness of monitoring field development.

Modern technology of drilling and construction of horizontal wells allows for effective development of complex oil fields hard-to-recover oil reserves includes off low-permeability (less than 1-2 mD) and hyper-low-permeable (0.01-0.0001mD) fields. The latter in Russia include Bazhen, Domanic and Achimov fields. Their development provides for the mandatory completion of HW with Multiple-Fractured Horizontal Wells (MFHW). Experience in the development of layers of the specified type for Gazpromneft PJSC shows that the highest oil production rate is achieved if the MFHW system reveals not only the low-permeability rock matrix, but also captures the highly conductive (typically fractured) streaks — "strata-conveyors" (the latter may also be located in neighboring geological and stratigraphic differences). The difference in the permeability of such highly conductive layers and the hyper-low-permeable matrix of the host rocks can be very significant (up to 10 6 !). In addition to the positive aspects of the presence of highly conductive layers in the section associated with the achievement of high initial oil flow rates in new wells, in the process of further development, negative consequences may arise as a result of premature (even unpredictable) gas and water breakthroughs through narrow fractured layers. Is it possible to take into account the risks of loss of well productivity as a consequence of the pronounced geological heterogeneity of these fields, even if the scale of the impact of this heterogeneity is still difficult to assess by modern research methods? In this paper analyzes some of the results of core, logging, well testing and indicator studies with the allocation of characteristic features indicating the presence of local highly conductive fractured layers in the section of the oil the Bazhen-Abalak complex (BAC).

Due to the deterioration of petroleum resources in the Republic of Belarus, unconventional reservoirs, which contain hydrocarbons in "shale-like" low-permeable rocks, which include Domanic deposits, become increasingly important. These rocks containing hydrocarbons are both producing oil and at the same time they are not reservoirs in the traditional sense ( Varlamov A. I. et al., 2017 ). The most common technology for developing unconventional reservoirs is drilling horizontal wells with multi-stage hydraulic fracturing. The technological efficiency of drilling such wells will primarily depend on getting into the so - called "sweet spots" - places characterized by the best petrophysical, pyrolytic and geomechanical properties. This ultimately determines the need for a comprehensive study of hydrocarbon deposits in unconventional reservoirs. This article describes the workflow for studying unconventional reservoirs of one of the fields of the Pripyat trough of the Republic of Belarus. Studying these reservoirs was a challenge because due to geological and surface conditions no seismic data was available. The first well logging results showed the absence of significant rock anisotropy detected by standard methods of acoustic logging. This caused difficulties in determining the direction of drilling horizontal wells. There were also insufficient results of core studies of wells, including fully geochemical and geomechanical studies. Carrying out a comprehensive study of promising formations and confirming their oil bearing capacity required making a comprehensive program presented below, which outlined the types of studies that would provide necessary information about lithological, petrophysical, pyrolytic, and geomechanical characteristics of unconventional reservoirs of the field under study. Core studies performed within the integrated study confirmed that the studied sediments are source rocks. At the same time, according to the results of pyrolytic research, it was found that the rocks contain both in-situ hydrocarbons, and the ones which migrated from the underlying formations. The set of geophysical studies carried out on the legacy wells, including logging, hydraulic fracturing and surface seismic monitoring, allowed determining the direction of maximum stress, which eventually allowed determining the direction of drilling horizontal wells. The set of studies described in this article can be used in the study of other unconventional deposits of the Pripyat trough, belonging to the Domanic type.

The era of production of readily available oil, which requires a relatively low level of capital costs, engineering solutions and the lack of use of new technological solutions, is over. At the moment, in the world and, specifically, in the perimeters of Gazpromneft, the bulk of the assets of hydrocarbon fields are complex in type and structure deposits with sufficiently high oil reserves, requiring both high capital costs and the adaptation of new technologies for effective development. Achimov formations Ach18-1 of the Yamburg deposit are bright representatives of the reservoir with a complex structure and very low, even for Achim formations, permeability. Average permeability of formation Ah 18-1 0.15 mD. At the moment, the only technology that allows achieving the profitability of the project is the use of wells with multi-stage hydraulic fracturing. However, a high share of hydrocarbon raw materials remains in the formation and for development, new technologies are being sought that will increase the level of net discounted income, as well as increase the oil recovery ratio. For consideration, the technology of mixing oil displacement with gas was chosen as one of the most promising technologies for the conditions of the Yamburg oil field. Gas injection technology was tested in a number of countries: the USA, Canada, Brazil, Venezuela and Norway, including was considered on some projects of Russia (USSR) ( Figure 1 ). There are no direct analogues for Yamburg conditions, however, this technology allows us to obtain a REF increase of 1.5 to 2 times among the fields considered, on average, REF with the use of mixing displacement is about 46%, the increase relative to the standard Flooding is 7-12%. The promise of this method is that it can be used in deep-lying formations with low filtration-capacitive properties, high thermobaric conditions, the method allows not only to maintain formation pressure, but also to increase the oil recovery coefficient. Increase of oil recovery coefficient is achieved due to achievement of mixing pressure during gas injection, which leads to decrease of residual oil saturation and increase of phase permeability in gas-oil system. It is worth noting that the characteristics of the reservoir oil of the object under consideration (high gas content, a significant proportion of light fractions in the reservoir fluid composition) favor the use of gas methods to increase oil recovery, since the values of minimum mixing pressures for various types of injected gases (including pure methane and nitrogen) are lower than the initial reservoir pressure. Figure 1 REF when applying mixing displacement technology. To assess the efficiency of mixing displacement at the Yamburg field, analytical calculations were carried out to determine the minimum mixing pressure with the formation oil of the Ach18-1 formation (the main development object). Based on the results of the calculations, the following conclusions were made: The mixing pressure for the formation oil of the Yamburg field varies from 417-500 depending on the composition of the injection gas. Mixing pressure practically does not depend on the degree of depressurization of reservoir oil (possibility of development in dissolved gas mode with switching to gas injection at any moment) To clarify the MMP values, it is necessary to conduct slim tube for different injection gases and on a larger number of oil samples.

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.

This article describes general information about the geological structure, the identified complications during the construction of wells at the Kovykta gas condensate field associated with abnormally high reservoir pressure (AHRP). Based on the initial data and analysis of previously drilled wells, the requirements for equipment, the choice of drilling fluid density and the applied engineering solutions were formed. The goals and objectives of the project are outlined and the conditions in the process of drilling the section are presented, technological schemes and procedures are compiled during operation. Introductory training on managed pressure drilling technology was conducted with the personnel of the drilling and oilfield service companies. The revealed new mining and geological conditions and the complications that arose with them, and well-timed decisions allowed us to achieve the design depth of the section. The possibility of using brine for drilling the section using mudcap drilling technology was also confirmed. According to the final data, after drilling and fastening the section, new goals have been set for new wells at AHRP intervals. During the section drilling, various works were repeatedly performed in the presence of wellhead excess pressure, but the developed procedures, analysis, and risk assessment allowed to complete the project without incidents or accidents. Based on the gained experience, a number of decisions were made to optimize the well construction process at the field.

Carbonate reservoirs are often characterized by high pressure and high content of H 2 S and CO 2 . For these reasons, drilling the reservoir is the most challenging activity for such fields and long-term zonal isolation across the reservoir section is one of the primary requirements. The work describes the development, laboratory evaluation, implementation and long-term assessment of self-healing properties for H 2 S/CO 2 resistive, low Young's modulus, expandable cement system. The 2.05 SG cement system was specially designed and implemented on 12 wells at N oil field for guaranteed long-term zonal isolation of production reservoirs containing high concentration of H 2 S and CO 2 . The paper includes rationale and details of CO 2 and H 2 S resistive cement system design. Self-healing was tested by pumping simulated reservoir fluid composition, through induced fracture in cement sample at downhole conditions. Observed fracture closure leading the gas flow stoppage is a result of cement matrix in the crack swelling when in contact with hydrocarbons. To address risk of perforations closure and ensure cement integrity in perforation zone, when in contact with hydrocarbons, cement samples were exposed to aromatic oil for twenty months. Long-term zonal isolation was assessed by monitoring the cemented wells for the six years period. To overcome these problems, self-healing cement system and durable cement systems were developed to ensure well integrity during the life of the well, providing competent annular pressure seal. Extensive laboratory work was undertaken to engineer the slurry to the required specifications. Self-healing cement is based on a responsive material with intrinsic self-healing properties automatically activated upon hydrocarbon exposure to rapidly seal the damage; within hours the downhole well integrity is restored. This reduces the potential health, safety and environmental risks and the extra costs associated to remedy these problems including loss of production. Self-healing system includes expanding additives and expands after setting, improving cement bonding and sealing micro annuli that otherwise can cause unwanted gas migration. Due to its improved mechanical properties and low Young's modulus it can withstand cement sheath stresses during well operations due to changes in the operating temperature and pressure. For a formation where hydrocarbons are not present to trigger the self-healing mechanism, the durable cement system is the solution to use. It has suitable components to optimize its mechanical properties to withstand pressure and temperature cycling. The slurry had a fit for purpose thickening time and rheology accomplished with excellent fluid loss control, static and dynamic stability for proper placement. Yard trials confirmed designed slurry compatibility with surface field equipment. Self-healing was achieved in the reservoir fluid composition, when tested at 60 degC and 34.5 MPa. Micro gaps or fissures, which might occur in the cement sheath along life of the well, would be efficiently closed and sealed. Cement also demonstrated ability to preserve integrity after exposure to aromatic oil for twenty months. This confirmed system applicability for placement across reservoir perforation zone. Mechanical properties of the cement were tested. Cement developed compressive strength of 25 MPa, tensile strength of 3.3 MPa, young's modulus of 7 GPa compared to 10 GPa for conventional systems same density. Lowered Young's modulus in conjunction with 1% cement self-expansion post setting provided additional guarantee of high-quality zonal isolation. Experience of pumping the system for 12 wells showed excellent mixability and pumpability in the field. Cement logging tools confirmed high quality of zonal isolation. Wells have shown absence of sustain casing pressure for six years. The CO 2 self-healing and resistant cement overcomes the deficiencies of conventional cement slurry in carbon dioxide environments. Using of self-healing cement systems historically showed superior long-term zonal isolation efficiency. However, there is no available information on efficiency and performance of such systems in high H 2 S/CO 2 environment. Application of such system is limited for production zones. This work shares unique experience of design execution and performance evaluation of self-healing system in described complicated conditions. Moreover, the paper presents correlation of advanced laboratory testing methods with long-term cement performance in real well conditions.

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.