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.

One of the engineering tasks of hydraulic fracturing design is the correct selection of the propping agent. Ceramic proppant, which is used in most fields in Western Siberia, makes a proppant pack that is several times more permeable than the formation (sometimes even 1000 times). However, the gelling agent used for treatment, depending on the size of the proppant, reduces the permeability of the proppant pack from 2 to 5 times. However, workover operations after hydraulic fracturing and during production period has a significant colmatage effect on the near-wellbore zone and can significantly reduce the productivity of the well. A common practice in the fields of Western Siberia is to prop a fracture at the near-wellbore zone with a proppant of mesh size 12/18. Despite a small difference in the calculated skin factor, the analysis of operations at the Salym group of oilfields shows a significant change in the production decline rate on wells with 16/20 and 12/18 mesh size propping agents. Engineering group of the Salym group of oilfields conducted trials on hydraulic fracturing treatments with a mesh size 10/14 and, after successful results, 6/10 proppant. The treatment results, lessons learned and the analysis of production of these wells is the scope of this work.

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.

The article covers methodology for rapid assessment of optimal development parameters for offshore fields. The first stage determines maximum allowable expenditures for field construction that make the project efficient, following selection of the offshore facility type required for production. The second stage evaluates the well density for every cost-effective offshore facility considering the best economical option for field development.

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.

One of the most important tasks when developing oil fields with horizontal or directional wells is the inflow distribution monitoring along the wellbore. Possible irregularities in the inflow are primarily associated with heterogeneity in the filtration distribution and capacitive properties along the wellbore, unevenness in the depression distribution, possible overfilling of the wellbore, partial or complete blockage of sand filters by mechanical impurities or clay material, imperfect development of the wells (when part of the mud cake remains on the wall of the well), gradual clogging of the bottomhole zone pores, water breakthroughs and gas outs, or other reasons. Inflow profile monitoring allows identifying why the well performance has decreased and timely planning and carrying out appropriate geological and technical measures. Also, this information allows timely updating hydrodynamic models of field development to properly make strategic decisions. This paper presents the results of bench tests of a new active thermometry technology using a distributed temperature measurement system

The operation of gas wells is often fraught with complications due to water accumulated in the perforation interval and wellbore, and destruction of the bottom-hole zone. These complications drive up pressure losses and decrease operating well flow rates and production capacities of deposits. This article presents proposals for unburdening gas wells in the Vostochno-Makarovskoye field.

Liquid hydrocarbon quantity optimization is among key technological indicators in the gas condensate fields development. To achieve it one needs to select and maintain optimal well-operating conditions. In this case, multiphase flow measurements are prioritized as an important optimization tool. The article presents a proven record of implementing the technology of instrumentalised virtual multiphase flow metering in the wells of the Vostochno-Makarovskoye gas condensate field to increase the efficiency of liquid hydrocarbon production. Virtual flow metering technologies that use modeling methods and adapt models to actual well-operating parameters aiming at determining well production rates are becoming increasingly popular. At that, the quality of the data at the model input does not often guarantee a qualitative determination of multiphase flow parameters. This article presents a track record of building a virtual multiphase flow meter based on single-phase streamer flow meters mounted on gas wells. Venturi flow meters were used. A series of well tests were conducted in various modes. To configure the streamer model, additional tuning studies were conducted on the separator. While testing the wells, the results of constructing a streamer model were verified by nodal analysis.

The well integrity monitoring including Sustained Annulus Pressure (SAP) assessment on offshore stationary platforms in the conditions of a limited number of well slots plays an important role in the development of oilfield with thin oil rims and a massive gas cap. The presence of SAP leads to uncontrolled release of gas or liquid to the surface, disruption the operating condition of the wells and its completion components, that overall can result to severe accidents at the offshore oil and gas production facility. Another difficulty that SAP brings is secondary gas cap accumulation across untargeted reservoir zones that might lead to blowouts in operating wells. To identify the causes of SAP, constant monitoring of annulus pressure, as well as proper diagnostics are needed. One of the most reliable and effective methods for identifying SAP causes is Through-Barrier Diagnostics that able to accurately localize reservoir-sources of SAP behind multiple casing strings in the wells, which helps production engineers further production strategy and weighted workover planning. Conventional diagnostics on identifying SAP sources is significantly limited by complexity of the well construction and downhole equipment. This paper describes using of Through-Barrier Diagnostics on the sources of SAP identification on the ice-resistant stationary platform named after Yuri Korchagin, detailly explains the approach and challenges on real case studies. High precision temperature and passive spectral acoustics play a key role in described technique. Passive spectral acoustics, which have a scanning radius of about a few meters, helps to detect fluid flows in the reservoir and behind casing channels in cracked cement.

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.

For the first time, one of the Russian oil company empowered to change standard approach to well production optimization by using a new generation of intelligent completion technology - the all-electrical system with fine inflow control and downhole flow characteristics measurements that were previously unavailable in real time. The experience of optimization approach, which is unique for both the Russian and the world oil industry, is described in this article. The standard approach to well optimization was time consuming and, in some cases, associated with comprehensive testing and well interventions. The new approach allows testing and optimization of wells in real-time within shortest period with no production logging, well shutoffs and production loss, and allows to obtain phase rates and fractional composition of the flow for each well interval. The described technique was consistently introduced and improved by x-segment specialists from production and science departments. Accumulated real time data and special downhole testing made it possible to obtain a unique knowledge about zonal flow behavior during various stages of well operations stable work, well testing, build ups, shut offs, well starts, clean ups and optimizations. The new technique at this stage allows: Optimize well clean-up; Introduce new well testing procedure with minimum production, Minimize interventions; Reduce time for full well optimization cycle to 2 days; Introduce procedure for well shut-in preparation for wells with high GOR and watercuts; Minimize cost and risks associated with interventions, zonal testing, optimizations. Background for the described technique introduction are innovative scientific research and experiments with the aim of obtaining fractional composition and phase rates in real time with a minimum set of downhole sensors. The article describes the theoretical foundations of the approach, innovative areas of research and methodology for improving the models and applied correlations. Scientific solutions coupled with implementation of advanced completion technologies, machine learning methods, as well as depth of field experience have improved the approach to solving well optimization challenges of wells on the North Caspian field. The experience gained from the first three wells was used to expand the technological and interpretation capabilities of the described solutions. The one of the key advantages of proposed optimization methodology applied on wells with presented technological equipment is simplicity and elegancy of approach. The total number of downhole valve position change during various operations for three wells exceeded 1500 within less than 1 year of operation time. To the moment, the methodology, the experience gained, the results of the approach implementation are unique for the oil industry. The presented technologies and digital solutions make it possible to improve well management strategy significantly and, of course, will be interesting to engineers of field management department.

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.

Acid treatment is a common well stimulation technique widely used for both oil and gas wells. However, there is a challenge, that for any given acid solution, rock lithology and permeability, and reservoir conditions, there are optimum values of acid injection volume and rate. Deviation from these optimal values during stimulation treatments reduces the acid job efficiency. We developed a robust and efficient method of identification of the optimum parameters based on digital core approach. The developed workflow includes: a) construction of a digital avatar of a core sample using 3D microCT tomography; b) pore-scale direct reactive flow modeling using a combination of the chemical kinetics/thermodynamics (in assumption of partial local equilibrium) with the method of density functional theory in hydrodynamics (an efficient tool for pore-scale modeling of multiphase flow able to handle different complex physical phenomena); c) core scale simulations in the framework of the Darcy based approach using upscaling from the results of the direct pore-scale simulations; d) input of the obtained parameters into the acidizing simulator to determine optimum acid type, rates, and volumes. We illustrate the developed workflow on example of an optimum injection rate determination in the case of Silurian dolomite dissolution by hydrochloric acid. The pore-scale simulations were performed using 3D microCT models with 2.5 μm/voxel resolution. These simulations allowed to determine the dependence of dolomite dissolution rate on the fluid injection rate and predict the transport properties of damaged rock. The correlations obtained from high resolution simulations were then applied in core-scale modeling of dissolution process using continuous Darcy based model (with 100 μm/voxel resolution). The transport properties of a core were populated using the results of pore scale simulations. Then several core scale simulations of dolomite dissolution with different acid injection rates were performed to obtain numerically the dependence of its influence on the number of pore volumes injected until the breakthrough (PVBT). PVBT dependence on the injection rate in a form of characteristic curve was incorporated into the advanced acidizing simulator. Being calibrated this way, the simulator was then used to model acidizing treatment in a dolomite reservoir with the similar properties as digitally acidized core. Modeling showed that post stimulation skin values are lower and expected wormhole length is bigger when digitally calibrated pore volume to breakthrough (PVBT) curve is used, if compared with modelling of the same treatment with non calibrated acid-rock interaction curves. Consequently, outcomes of this well scale modeling suggest that the use of digitally calibrated PVBT curves results, for this case, in optimization of required acid volume and associated operational footprint. The suggested approach improves the process of obtaining PVBT characteristic curve by application of digital core analysis technique. It allows to test numerous "what if’ scenarios and to evaluate the effect of different factors on mineral dissolution rate at pore scale. This paves the way for improvements in acidizing job design by increasing the consistency between the models used for reactive flow modelling and pore scale heterogeneity of real rocks.

A substantial part of the residual reserves of theVolga-Ural region oil and gas fields (Russia) is associated with objects with a complex geological structure and reduced productivity. Cost-effective development of such objects became possible with the introduction of modern oil production technologies. One of them is the drilling of wells with complex completion, primarily horizontal and multilateral. The article describes the experience of horizontal multilateral drilling in carbonate deposits using the technology of laterolog resistivity borehole imaging. The effectiveness of multilateral wells regarding reducing geological uncertainties and the success of commissioning is analyzed. The main part of the multilateral wells under consideration was drilled within the Upper Visean-Bashkir carbonate oil and gas complex, where reservoir properties are characterized by significant variability both in area and in section. The structural plan, despite the presence of some general regional patterns, is subject to significant changes within local uplifts. For geological support, we used the methodology for updating structural surfaces and the geosteering model during the sequential drilling of each of the borehole of multilateral well. The update was made before drilling each subsequent wellbore according to the results of the previous one. The input information for the refinement of the section was the structural dips allocated in real time according to the resistivity image of the borehole wall. This made it possible to reduce geological uncertainties and position the all boreholes in the target zone. As an illustration of the experience of the described methodology, the article considers three multilateral wells drilled in carbonate deposits of the Bashkir and Serpukhov stages. An analysis of the drilled wells confirms the effectiveness of the multilateral drilling in reducing the risks of drilling a well outside of productive intervals due to the consistent refinement of the geosteering model based on the results of the construction of each of the wellbore. In certain cases, it is also advisable to use the multilateral geosteering strategy, in which the first well penetrates the formation at maximum vertical depth to localize the most productive intervals, and subsequent horizontal sections are located within the intervals of the best reservoir properties encountered during drilling of the first section. In this regard, the application of the technology of the wellbore laterolog resistivity images can also be used to solve the problem of drilling the maximum thickness of the reservoir. The second and subsequent boreholes alternatively couldbe placed with penetration to the maximum vertical depth as well, to engage in the productionas many oil-saturated interlayers as it possible. The optimal trajectory profiles, advanced logging methods during drilling and suit for purpose well placement strategyall together can ensured an increase of reservoir exposure despite the deterioration of geological conditions. The use of an integrated approach to the design and construction of multilateral wells makes their drilling useful not only to clarify the geological features of the target zone, but also to solve a number of technological issues. Thus, a successful multilateral well can serve as an alternative to multi-stage hydraulic fracturing and contribute to more uniform production compared to single horizontal wells.

The present work is dedicated to the problem of developing oil and gas condensate pools with thin oil rims for neocomian deposits in the Urengoy region, and to the search for effective methods of oil production from thin rims. The key problems in the development of thin rims are the low cumulative oil production per well, as a result - low profitability and oil recovery ratio. The reasons are known: a sharp decline in initial oil rate due to the rapid increase in water cut and growth of gas factor associated with the water and gas coning. The results of hydrodynamic modeling at early stage in the development of oil rims often lead to optimistic forecasts that are not confirmed in practice. The paper provides an analysis of the reasons for optimistic calculations, tuning up models for the results of the development and operation of oil wells with different completion relative to the GOC. Obtaining history-matched oil and gas production systems made it possible to obtain a more reliable production forecast for oil wells, to substantiate the preferred target subsea depth for the completed interval in the rim and the type of completion. Scenarios with the completion of the horizontal section at a distance of one third from the GOC and OWC, or in the middle between the contacts, have been considered and analyzed. A comparison of the calculated performance of the wells with the actual one had been made. An economic evaluation of the operational efficiency of wells drilled on thin rims shows that their profitability based on oil production is marginal. The closer completion intervals of the oil horizontal wells to the GOC the higher economic efficiency of their operation due to additional volumes of gas and condensate production from the gas cap. The use of double-wellbore and multi-lateral completion of horizontal wells in the oil rim increases the economic attractiveness of the project. The integrated approach proposed in the paper to the organization of production and oil and gas processing systems from such oil wells makes it possible to technologically efficiently operate wells and ensure almost full utilization of associated gas. The joint development of gas condensate pools with thin oil rims allows for the cost-effective development of the ones.

A concept has been developed for gas, gas-condensate and oil fields exploitation planning in the Arctic region, taking into account the limitations of the existing external and internal infrastructure. The work was carried out as part of an integrated project management system to determine business opportunities and initiate the transition of field development projects to the pre - project development phase (Pre - FEDD). The paper considers the formations and geological structures of the Bolshekhetskaya Depression in the license areas: License area "Nakhodkinskiy" Licensed area "Pyakyakhinsky" License area "South Messoyakhsky" License area "Halmerpayutinsky" License area "Salekaptsky" Licensed area "West Tazovsky" License area "Vareisky" The choice of the profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure of the formation during the well construction, as well as include all productive layers in the development, reduce the risk of complications during operation. Usage of longer horizontal wells will reduce drill footage; to increase the flow rate and profitability of wells; it is more rational to use formation energy due to lower values of depression on the formation and correspondingly reduced losses of condensate in the formation.

An efficient hydrocarbon field development requires implementing the current field production control accompanied by various surveys. Historically, classic approaches do not yield favourable results and ensure high information value,which results in the necessity for state-of-the-art technologies. One of these technologies could be the production logging using markers. The goal of this article is to study various sampling techniques for convergence of quantum markers identification results during the horizontal well injection logging. The present article is dedicated to the studies comprising of a comprehensive reservoir fluid sample analysis with subsequent production logging evaluation of a multi-stage horizontal well at Sredne-Nazymskoye oilfield. The article covers the oil and water inflow monitoring in a horizontal well treated with 15-stage fracturing. The technology, which serves a basis for this analysis, involves using a marked proppant with polymer coating. Flow profiles are evaluated by calculating the markers of different codes in a fluid sample, and every signature (code) corresponds to a particular interval where a man-made crack is induced. For this study the special sampling schedule was made involving an extensive reservoir fluid sampling in order to perform representative selection and making references to external and engineering factors such as well operation conditions, flow pattern, flow rate, volume components, etc. Test review allowed getting a general idea of how reservoir fluid will be sampled at non-conventional deposits qualified as the hard-to-recover reserves in order to improve production logging information value both at qualitative and quantitative levels.

Currently, there is a growing tendency to involve unconventionals in development, therefore drilling, completion and production stimulation technologies are being intensively developed. Cost-effective development of hard-to-recover reserves (HTR) is possible only with the involvement of horizontal drilling and multi-zone hydraulic fracturing. Due to the fact that conventional methods of PLT of horizontal wells for traditional reservoirs have a number of difficulties when operating on unconventionals, alternative methods for well surveying using flow indicators are increasingly in demand that allow multiphase monitoring of long-term multiphase inflow along a horizontal hole without involving additional equipment, well kill, etc. The objective of this article was to obtain confirmation on the profile distribution and inflow composition after the MSHF operation for further well intervention planning in the main unconventional of the Russian Federation – the Bazhenov formation. In a study, the inflow was monitored for oil and water phases in horizontal wells with multistage hydraulic fracturing (from 9 to 15 stages) and the use of the marked proppant. The technology of marker studies of horizontal wells consists in a single placement of high-precision indicators of fluid inflow in hydraulic fractures. After the completion of the MSHF field operation and putting the well into operation, sampling of the reservoir fluid from the wellhead was carried out and they were analyzed on the quantitative distribution of markers of each code corresponding to the interval distribution of oil and water flow rates. The monitoring of marked wells was carried out periodically for several months. The flow profiles of horizontal holes were constructed on the basis of analysis of samples and analytical data obtained. The results of the work allowed to analyze efficiency of stimulation of horizontal wells for each of the stages of hydraulic fracturing. Unlike traditional research methods, the main advantage of the presented technology for monitoring the horizontal inflow profile is the lack of need for using special means of device delivery, the use of the technology is not fraught with risks of seizure of equipment and ambiguity of interpretation. It is also important to note that this technology allows monitoring continuously for several years without additional measures. Comparison of research and monitoring methods is shown in table No. 1. Table No. 1. Comparison of the characteristics of various types of monitoring of well inflows Type of monitoring Classical set of PLT using CT Distributed fiber optic sensors for online monitoring Marked proppant Monitoring period A few hours Up to several years (depending on the quality of the optical material and the number of removal of solid particles from the rock) Hydrophilic, oleophilic, gas – more than 3 years (depending on conditions) The need to stop or change the well operation mode Yes No No Bench tests Yes No Yes Number of studies per year 1-2 Continuous monitoring 6-12 (selectively upon customer request) Laboratory Not applicable Not applicable Yes Multi-hole, multilateral wells or wells with a large distance of the bottom from the vertical Opportunities are limited Yes Yes Use in cemented shanks Yes No Yes Use in old/new wells Yes For new wells Yes Use in open holes Yes (there are restrictions) No Yes (there are restrictions) Assessment of the quality of bottom-hole or hydraulic fracturing treatment No KO – Yes Hydraulic fracturing – limited Yes The possibility of increasing the efficiency of field development based on the results Yes Yes Yes Limitations of the technology Availability of a horizontal hole; Risks of downhole operations; The complex process of running in hole; Repair and maintenance is required; Not a mass decision Limited use in high-viscosity oil; Depends on the success of the hydraulic fracturing operation

This work describes the technological solutions that were used in the development of the Novoportovskoye field - a large oil and gas condensate field in the Yamalo-Nenets Autonomous Okrug. In particular, optimization of the associated gas utilization strategy is considered by organizing the reservoir pressure maintenance. The decisions were based on 3D mathematical calculations, analytical estimates, analysis of field information and reservoir simulation. The paper presents the results of calculations performed to determine the specific efficiency of gas injection at productive formation. Additionally, weight coefficients of gas injection were calculated for gas well sites to identify the best injection zones. The paper provides the estimation of the current effect of the continuous two-year gas injection. The formation response to the gas injection into the gas cap was estimated by the usage of pressure-observation wells data, data from wells equipped with fiber-optic monitoring systems and by performing retrospective simulation. The calculations made it possible to achieve complete utilization of associated petroleum gas and significantly increase the oil recovery factor.