Production Rate Of Wells Research Articles

Prospects for increasing the productivity of horizontal wells using integrated technologies on the example of objects in the Ural-Volga region

The paper highlights the issues of the efficiency of the operation of horizontal wells with multistage hydraulic fracturing. The experience of repeated hydraulic fracturing with preliminary preparation of the trunk by hydroblasting perforation shows effectiveness in restoring well productivity. The advantage is the possibility of selective injection of acid and proppant in a certain interval, stimulation of previously not involved in the development of layers and interlayers. This approach significantly expands the scope of application of integrated technologies for the intensification of oil production, in particular, with a high level of uncertainty arising during the development of deposits in this region. It is the introduction of relevant and advanced technologies to increase oil production rates of wells that is the source of technology development and their replication at other oil production facilities. During the retrospective analysis, the effectiveness of the work was assessed depending on various geological, physical and technological factors. It was found that the main reasons affecting the effectiveness of the operation are the orientation of the horizontal trunk along the direction of regional stress, an increase in the points of hydroblasting perforation, and the distance to the injection well. The latter, in turn, is the most important indicator in the planning of hydraulic fracturing, especially in weakly cemented carbonate reservoirs. The conducted research in the field of selecting the optimal method of influencing the target oil production facilities of the Ural-Volga region will allow subsoil users to choose the most relevant and effective way to improve the technical and economic performance of enterprises. The identified reasons, which have a significant impact on the final productivity of wells, must be taken into account when solving various tasks of improving oil production processes in long-term oil-bearing territories. Keywords: hydraulic fracturing; hydrosandblast perforation; multi-stage hydraulic fracturing; horizontal well; formation; productivity; proppant; objects of the Ural-Volga region.

Determination of the degree of coal deformation and its effects on gas production in the southern Qinshui Basin, North China

Coal deformation significantly impacts coalbed methane (CBM) productivity. However, existing methods are incapable of quantitatively evaluating coal deformation on a high accuracy when there is limited core recovery from a CBM well. This study proposes a well logging coal structure index (WCSI) to quantify the degree of coal deformation. The WCSI of targets is calculated based on the data from well logs and coal cores, and it can also be estimated from well logs when no coal cores are recovered from wells. Thus, the WCSI can be applied to the regional-scale evaluation of coal deformation degree, and its effectiveness has been validated by data for 245 samples from the No. 3 coal seam in 55 exploration wells in the southern Qinshui Basin (SQB). Results indicate that the reservoir permeability and hydraulic fracturing effectiveness depend on the degree of coal seam deformation, which further affects the unique distribution of gas production in the known production regions in the SQB. Generally, the lowly deformed coal seam (WCSI (avg.) < 40) occurs mainly in the tectonically ‘stable’ regions (no faults or only small-scale faults development) where the micro-fractures/cleats in coal are not well developed. Low WCSI (avg.) commonly indicates low permeability (<0.06 mD) and poor hydraulic fracturing of the reservoir, resulting in relatively low gas production rate of wells in these regions. Secondly, the moderately deformed coal seam (40 < WCSI (avg.) < 60) is mainly found in areas close to moderate-scale faults, where coal seams have relatively high reservoir permeability (>0.06 mD) and hydraulic fracturing is easiest. This causes high gas production rate from wells in these regions. Thirdly, the highly deformed coal seam (WCSI (avg.) > 60) is generally found close to large-scale faults, indicating very low reservoir permeability (<0.03 mD) and the worst effectiveness from hydraulic fracturing of the reservoir, resulting in the lowest gas production rate of wells in these regions. In summary, the production efficiency from CBM wells in the SQB can thus be described in terms of the WCSI (avg.) value, and hence this parameter can help with preliminary forecasting gas production.

A comparative machine learning study for time series oil production forecasting: ARIMA, LSTM, and Prophet

It is challenging to predict the production performance of unconventional reservoirs because of the sediment heterogeneity, intricate flow channels, and complex fluid phase behavior. The traditional oil production prediction methods (e.g., decline curve analysis and reservoir simulation modeling forecasting) are subjective. This paper presents a machine learning-based time series forecasting method, which considers the existing data as time series and extracts the salient characteristics of historical data to predict values of a future time sequence. We used time series forecasting because of the historical fluctuations in production well and reservoir operations. Three algorithms were studied and compared to address the limitations of traditional production forecasting: Auto-Regressive Integrated Moving Averages (ARIMA), Long-Short-Term Memory (LSTM) network, and Prophet. This study starts with the representative oil production data from a well located in an unconventional reservoir in the Denver-Julesburg (DJ) Basin. 70% of the data was used for model training, whereas the remaining 30% of data was used to evaluate the performance of the above-mentioned methods. Then, the decline curve analysis and reservoir simulation modeling forecasting were applied for comparison. The advantages of the machine-learning models include a simple workflow, no prior assumption about the reservoir type, fast prediction, and reliable performance prediction for a typical fluctuating declining curve. More importantly, the ‘Prophet’ model captures production fluctuation caused by winter impact, which can attract the operator's attention and prevent potential failures. This has rarely been explored and discussed by previous studies. The application of ARIMA, LSTM, and Prophet methods to 65 wells in the DJ Basin show that ARIMA and LSTM perform better than Prophet—probably because not all oil production data include seasonal influences. Furthermore, the wells in the nearby pads can be studied using the same parameter values in ARIMA and LSTM for predicting oil prediction in a transferred learning framework. Specifically, we observed that ARIMA is robust in predicting the oil production rate of wells across the DJ Basin.

Model-based characterization of permeability damage control through inhibitor injection under parametric uncertainty

Damage in subsurface formations caused by mineral precipitation decreases the porosity and permeability, eventually reducing the production rate of wells in plants producing oil, gas or geothermal fluids. A possible solution to this problem consists in stopping the production followed by the injection of inhibiting species that slow down the precipitation process. In this work we model inhibitor injection and quantify the impact of a set of model parameters on the outputs of the system. The parameters investigated concern three key factors contributing to the success of the treatment: i) the inhibitor affinity, described by an adsorption Langmuir isotherm, ii) the concentration and time related to the injection and iii) the efficiency of the inhibitor in preventing mineral precipitation. Our simulations are set in a stochastic framework where these inputs are characterized in probabilistic terms. Forward simulations rely on a purpose-built code based on finite differences approximation of the reactive transport setup in radial coordinates. We explore the sensitivity diverse outputs, encompassing the well bottom pressure and space-time scales characterizing the transport of the inhibitor. We find that practically relevant output variables, such as inhibitor lifetime and well bottom pressure, display a diverse response to input uncertainties and display poor mutual dependence. Our results quantify the probability of treatment failure for diverse scenarios of inhibitor-rock affinity. We find that treatment optimization based on single outputs may lead to high failure probability when evaluated in a multi-objective framework. For instance, employing an inhibitor displaying an appropriate lifetime may fail in satisfying criteria set in terms of well-bottom pressure history or injected inhibitor mass.

Identification of the Shale Production Model

The technique of appraisal have been proposed for the evaluation of the recoverable reserves according to production schedules for the total wells number of the same calendar year into operation. NPV formula representation and necessary conditions for optimality have been proposed. Recoverable reserves and rate of production (production decline) have been identified for the wells put into operation in 2012 – 2017. As a trend, the initial production rate of wells and recoverable reserves grew from year to year, as well as investments in one well. The ties between the length of horizontal wellbores multiplied by the volume of injected proppant and production parameters have been studied. The choice of production technology depends on the actual oil price. With an increase in the oil price, optimaly coordinated increase both the recoverable reserves and the rate of production at the well.

Physics-based Residual Kriging for dynamically evolving functional random fields

We present a novel approach named Physics-based Residual Kriging for the statistical prediction of spatially dependent functional data. It incorporates a physical model—expressed by a partial differential equation—within a Universal Kriging setting through a geostatistical modelization of the residuals with respect to the physical model. The approach is extended to deal with sequential problems, where samples of functional data become available along consecutive time intervals, in a context where the physical and stochastic processes generating them evolve, as time intervals succeed one another. An incremental modeling is used to account for both these dynamics and the misfit between previous predictions and actual observations. We apply Physics-based Residual Kriging to forecast production rates of wells operating in a mature reservoir according to a given drilling schedule. We evaluate the predictive errors of the method in two different case studies. The first deals with a single-phase reservoir where production is supported by fluid injection, while the second considers again a single-phase reservoir but the production is driven by rock compaction.

Influence of Frequency of Wave Action on Oil Production

When elastic waves act on rocks, the structure of the void space changes. The nucleation and formation of new cracks is possible. Wave action technologies are divided into two groups: with a frequency of less than 100 Hz and a frequency of more than 1 kHz. In the intermediate zone, no completed works and studies of wave action were found. The paper studies the results of the impact of elastic waves with different frequencies and amplitudes on oil production. With low-frequency exposure, an increase in permeability values is noted to a greater extent due to the appearance of new and an increase in the size of existing cracks. With high-frequency exposure, the viscosity of reservoir oil is greatly reduced. The greater the value of the initial viscosity, the more intense it decreases when exposed to high-frequency waves. For the Perm Territory, a comparison was made of the results of wave processing of production wells depending on the frequency of exposure. As the impact frequency increases, the average oil recovery after wave treatment decreases. With an increase in the frequency of exposure, the duration of operation of a well with increased oil production after wave treatment decreases. Models have been obtained to predict the time of operation of wells with additional oil production, additional oil production and an increase in oil production rate of wells after wave action. As a result, it can be noted that the most effective technologies are those with a lower frequency, but a large amplitude of exposure.

Indirect estimation of the production rate of wells with low flow rate

The problem of measuring the flow rate of wells with low production rates is relevant for many oil fields. Conventional flow meters are not suitable for such cases, and installing an additional flow meter for each well is impractical. At the same time, wells with sucker-rod pumping units (the majority of wells) are outfitted with dynamographs for continuous diagnostics of the pumping equipment state. Dynamograms allow determining the theoretical flow rate of the well easily, however, a mathematical model is required to estimate the actual flow rate. For the correction of flow rate obtained from dynamograms, the authors of this study propose using models based on regression equations that link the calculated valueswith the measurements made by a reference instrument. The results of the experiments have confirmed the eligibility of this approach.

The Prediction of Future Oil Wells Production from Decline Curve Pattern

The production decline analysis is a traditional method of identifying wells production pattern and predicting its performance and life based on real production data. The study of the application the production decline curves using one of the empirical models either the exponential, hyperbolic or the harmonic decline curves which occur often in the later life of production units has been done. Decline curve analysis applies oil production versus time plots to extrapolate an estimation of the future production rates for wells. Production data were plotted in different ways to identify a representative decline model. In this study, the historical data were provided from five oil wells of the 4th pay formation reservoir in Zubair field in southern Iraq (Basrah region). These data were used to estimate the total future recovery of petroleum and the end of a productive life to the economic limit. The relationships between production rate, time, and cumulative production for each well were studied. The production data points for each well were analyzed separately to evaluate the effect of the change in the production and reservoir conditions on the remaining reserves. The typical decline curve was applied in each oil well and the estimation of total reserves isn‘t changing with the time or by the workover action.

Прогнозирование эффективности кислотного воздействия на основе построения математических моделей, учитывающих технологию и используемую композицию

Acid treatment is one of the most studied methods of stimulation of inflow in carbonate reservoirs. Nevertheless, enterprises are faced with the problem of reducing the planned production rates of wells after such events, which is due to geological and technological reasons. Taking them into account when planning impact and predicting effectiveness is possible by analyzing actual production materials using mathematical statistics methods. In this paper, using the example of a oil field in the southern part of Perm region, the main factors that influence the efficiency of acid treatments are identified, a number of multidimensional models are obtained that take into account their mutual influence and allow determining the result of a geological and technical measure.

Analytical Model for Predicting Productivity of Radial-Lateral Wells

An analytical model for predicting the productivity of Radial-lateral wells (RLW) drilled using radial jet drilling technology was developed in this work. The model assumes uniformly distributed equal-geometry laterals draining oil or gas under pseudo-steady state flow conditions within the lateral-reached drainage area. A numerical simulation and production data from three field cases of RLW were used to compare and validate the model. The result indicates that the model overestimates the well production rates for wells by 7.7%, 3.25%, and 8.8%, respectively. The error is attributed to several sources including, lack of data for well skin factor, uncertainty of horizontal permeability (kH) in the well area, uncertainty of permeability anisotropy (Iani), and uncertainty in bottom hole pressure (pw). Error analysis of uncertainties in kH, Iani, and pw showed that the model could predict productivity well with an acceptable error (10%) over practical ranges of these parameter values. Parameter sensitivity analyses showed that an increasing number of laterals, lateral length, and horizontal permeability would almost proportionally increase productivity. Well productivity is sensitive to well skin factor and oil viscosity, but not sensitive to the radius of the lateral.

Use of Mathematical Model to Predict the Maximum Permissible Stage Injection Time for Mitigating Frac-Driven Interactions in Hydraulic-Fracturing Shale Gas/Oil Wells

Abstract Frac-driven interactions (FDIs) often lead to sharp decline in gas and oil production rates of wells in shale gas/oil reservoirs. How to minimize the FDI is an open problem in the oil and gas industry. Xiao et al.’s (2019, “An Analytical Model for Describing Sequential Initiation and Simultaneous Propagation of Multiple Fractures in Hydraulic Fracturing Shale Oil/Gas Formations,” Energy Sci Eng., 7(5), pp. 1514–1526.) analytical model for two-fracture systems was extended in this study to obtain a general model for handling multiple fractures. The general model was used to identify engineering factors affecting the maximum permissible stage fluid injection time for minimizing FDI. On the basis of model results obtained, we found that increasing fluid injection rate can create more short fractures and thus increase the maximum permissible stage injection time before FDI occurs. Use of dilatant type of fracturing fluid (n &amp;gt; 1) can reduce the growth of long fractures, promote the creation of more short fractures, and thus increase the maximum permissible stage injection time before FDI occurs. It is also expected that injecting dilatant type of fracturing fluid at high rate will allow for longer injection time and thus larger injection volume, resulting in larger stimulated reservoir volume (SRV) with higher fracture intensity and thus higher well productivity and hydrocarbon recovery factor.

МЕТОДИКА ОЦЕНКИ ОЖИДАЕМЫХ ЗАПУСКНЫХ ДЕБИТОВ ГОРИЗОНТАЛЬНЫХ СКВАЖИН НА ПРИМЕРЕ ГАЗОКОНДЕНСАТНЫХ МЕСТОРОЖДЕНИЙ

Актуальность исследования обусловлена необходимостью нефтегазодобывающему сектору проводить корректный прогноз добычных возможностей планируемых к бурению скважин как на разрабатываемых, так и на новых месторождениях, вводимых в промышленную эксплуатацию. Оценка достижимых дебитов при планировании стратегии разработки месторождения позволяет не только прогнозировать проектные уровни добычи, но и принять решение по совершенствованию стратегии запуска и разработки месторождений. Рациональное планирование снижает негативное влияние на окружающую среду и ведёт к энерго- и ресурсосбережению, также минимизирует риски невыполнения плановых показателей, что является причиной постоянной корректировки объемов добычи в меньшую сторону, ускоряет запуск новых скважин, что повышает негативное влияние процесса бурения на окружающую среду, сокращает стандартное-рекомендованное время на мероприятия и снижает качество строительства скважин. Цель: оценка потенциала пласта в той или иной зоне при выборе размещения проектного фонда скважин перед бурением, приводящая к более рациональному планированию объемов добычи углеводородного сырья, которые определяются на основании расчетов гидродинамической модели. Объект: разрабатываемые и вводимые в промышленную эксплуатацию (новые) месторождения углеводородов. Методы: индивидуальный подход к каждой скважине при определении стартовых дебитов скважин на стадии проектирования разработки месторождения. Результаты. Разработана новая методика определения запускных дебитов проектных скважин, позволяющая более точно прогнозировать начальный дебит горизонтальной скважины в определенном районе на не введенном или уже разрабатываемом месторождении нефти, газа и газоконденсата.

Effects of fluid flow rate and viscosity on gravel-pack plugging and the optimization of sand-control wells production

Abstract Series of experiments were performed to simulate the invasion of formation sand into and the plugging process of gravel-pack at different viscosities and flowing rates of fluid. Two types of formation sands with the medium size of 0.10 mm and 0.16 mm and the quartz sand and ceramsite of 0.6—1.2 mm were used in the experiments. A new viscosity-velocity index (the product of fluid viscosity and velocity) was put forward to characterize the influencing mechanism and law of physical property and flow condition of formation fluid on gravel-pack plugging, and a new method to optimize the production rate of wells controlling sand production with gravel-packing was proposed. The results show that the permeability of formation sand invaded zone and final permeability of plugged gravel-pack have negative correlations with viscosity and flow velocity of fluid, the higher the flow velocity and viscosity, the lower the permeability of formation sand invaded zone and final permeability of plugged gravel-pack will be. The flow velocity and viscosity of fluid are key factors affecting plugging degree of the gravel zone. The viscosity-velocity index (v-v index) can reflect the flow characteristics of fluid very well and make it easier to analyze the plugging mechanism of gravel zone. For different combinations of fluid viscosity and flow velocity, if the v-v index is the same or close, their impact on the final gravel permeability would be the same or close. With the increase of the v-v index, the permeability of plugged gravel zone decreases first, then the reduction rate slows down till the permeability stabilizes. By optimizing production and increasing production step by step, the optimal working scheme for sand-control well can reduce the damage to gravel-pack zone permeability caused by sand-carrying fluid effectively, and increase well productivity and extend the sand control life.

To Interpret Rate Transient Analysis for the Determination of Reservoir Properties

Rate-time decline curve analysis is a major technique which is mostly used in petroleum engineering. Many methods are used for the determination of the decrease in the production rate within a given period of time. The main disadvantage of Arp’s decline type curve analysis is that it is only used for boundary dominated flow period; it is not used for transient flow period. The analysis of the Fetkovich is to determine the log-log type curve for both the transient flow period (early time period or infinite) and boundary-dominated flow period (late time period). Arps developed the type curve which shows the production rate decline with time for the finite reservoir or late time period. The exponential or constant flow decline, hyperbolic decline, and harmonic decline according to the value of decline curve exponent (b) is given by Arps. After that Fetkovich improved on earlier work done by Arps in predicting decline production rate of wells over a given period of time. The main objective of this study was to plotting the rate transient analysis curve. I will plot the Fetkovich type curve (combined early and late times region). The graph will be plotted between the dimensionless decline flow rate (qDd) and the dimensionless decline time” (tDd). This will be the objective of the study.

Peculiarities of hydrodynamics of pumps for the extraction of high-viscosity oil

Special features of the offshore fields currently under development are the high production rate of wells (~104bpd) and the high viscosity of the produced water-oil emulsion ~102-103сP, depending on the water cut. There are no special pumps designed for these conditions, so the production is carried out by the traditional centrifugal pumps suitable for the low-viscosity applications. For the selection purpose their testing on benches is performed according to the methods adopted in the oil industry at a frequency of up to 58 Hz (3500 rpm). The only difference is that instead of the traditional low-viscosity working fluid (water) high-viscosity Newtonian fluids (such as glycerin and oil) are used. Such tests only approximately correspond to well conditions; the following factors are not taken into account: the change in the properties of the liquid along the pump, the increase in the energy efficiency of pumps at increased shaft speeds, and, finally, the non-Newtonian rheology of the extracted emulsions. In our bench tests the shaft speed and the number of pump stages varied. The tests were carried out both on high-viscosity Newtonian fluid and water-oil emulsion. It was shown that the viscosity of the Newtonian fluid, due to its heating along the pump decreased by 20-30%. Moreover, the heating is not only due to internal friction, but also due to the compression of the liquid. A method of measuring of the effective viscosity of emulsions (which depends not only on the properties of the emulsion, but also the nature of its flow) based on the pump testing results has been proposed. It is shown that when the pump supply is changed the effective viscosity changes by approximately a factor of 3 times. The important phenomenon of increase of the efficiency of the pumps by 10 % during growing the frequency of rotation of the shaft from a traditional 50 Hz to 100 Hz was established. This effect occurs on both Newtonian fluids and emulsions.

IDENTIFICATION AQUIFER PARAMETERS THROUGH SINGLE WELL PUMPING TEST SERIES AT PT. KALTIM KARIANGAU TERMINAL, BALIKPAPAN, EAST KALIMANTAN

Aquifer Parameters are very important in groundwater and well management. The objective of this research is to determine aquifer parameter in order to be used in determining suitable production rate of well. Research was carried out in PT. Kaltim Kariangau Terminal, which is administratively, located in Balikpapan City, East Kalimantan, Indonesia. PT. Kaltim Kariangau Terminal has developed four wells with distance of each of well is between 50 and 300 meters, but it is a pity because just one well was completed by pumping test without observation well. Result of constant pumping test analyzing through Cooper – Jacob method has shown that value of Transmissivity (T) of aquifer is 319.0718283 m2/day, and it is known from geophysical logging and well construction design that the thickness of aquifer is 48 m, so hydraulic conductivity (K) of aquifer is 6.6473 m/day. Coefficient of aquifer loss is 0.0013 and coefficient of well loss is 0.0000008. Factors development of well could be classified as very effective with the well condition is properly designed and developed.

Production assessment of low production rate of well in a supergiant gas condensate reservoir: application of an integrated strategy

In this study, a novel and integrated strategy is proposed to investigate the problem of low production rate of gas well in a supergiant gas condensate reservoir. In this strategy, the nodal analysis approach is applied for production optimization and performance assessment of a real inclined well. A multi-layered gas condensate reservoir model was constructed and simulated using actual reservoir rock and fluid properties. Effects of reservoir rock and fluid model simplification on inflow performance relationship (IPR) curves were investigated. Also, five different tubing pressure drop models were evaluated using extracted pseudo spontaneous potential (PSP) data from reservoir model to select the most accurate one for computing tubing performance relationship (TPR) data. Then, accuracy of nodal analysis in prediction of well operating point was investigated through comparing with reservoir simulator results. Results of nodal analysis for this well indicated that a significant discrepancy exists between calculated and actual production rate. Sensitivity analysis on uncertainty parameters, skin factor and drainage radius, shows that skin factor of the investigated well varies between 11 and 12.9 for drainage radius in the range of 3000–20000 ft. Therefore, the problem of low well production rate was attributed to high skin factor as a result of formation damage. Also, results demonstrated that reduction of skin can lead to maximum 73% enhancement in daily volumetric gas production rate of well.

Quantitative Evaluation of Key Geological Controls on Regional Eagle Ford Shale Production Using Spatial Statistics

Summary Recent progress has increased our understanding of key controls on the productivity of shale reservoirs. The quantitative relations between regional Eagle Ford Shale production trends and geologic parameters were investigated to clarify which geologic parameters exercise dominant control on well-production rates. Previously, qualitative correlations for the Eagle Ford Shale were demonstrated among depth, thickness, total organic carbon (TOC), distribution of limestone beds, and average bed thickness with regional production. Eagle Ford production wells are horizontal, but it was necessary to use vertical wells that penetrated the Eagle Ford to map reservoir properties. No wells in the database had both production and geological parameters, and thus geological parameters could not be directly related to individual-well production. Therefore, spatial-interpolation methods derived from the Kriging and Bayesian methods with Markov-chain Monte Carlo (MCMC) sampling algorithms were used to integrate data sets and predict geological properties at production-well locations. The spatial Gaussian-process-regression modeling was conducted to investigate the primary controls on production. Results suggest that the 6-month cumulative production from the Eagle Ford Shale, in barrels of oil equivalent (BOE), increases consistently with depth, with Eagle Ford thickness (up to 180-ft thickness), and with TOC (up to 7%). Also, when the number of limestone beds exceeds 12, production increases with the number of limestone beds. The corresponding significance code indicates that the parameters most significant to production are TOC and depth (which relates to pressure and thermal maturation). Concepts and models developed in this study may assist operators in making critical Eagle Ford Shale development decisions and should be transferable to other shale plays.

TECHNOLOGY OF INCREASE OF WELL CAPACITY BY METHOD OF IMPROVING THE FORMATION EXPOSING CHARACTER

Background There is a well-developed system of underground gas storage (UGS) in Russia nowadays. It is a key instrument for smoothing out the peak loads and regulating the seasonal fluctuations in gas demand, for optimizing the operational modes of the main pipelines and investment costs of their construction, and for maintaining the flexibility and reliability of gas supplies to the consumers. At present, Gazprom operates 22 underground gas storage facilities at 26 gas storages in Russia: 17 - in depleted gas fields, 8 - in aquifers and 1 - in а salt cavern. The daily productivity highly depends on the quantity and quality of production wells. The quality of well is determined by its perfection in area of a filtration zone. The influence of these factors on production rate of wells in relation to the underground gas storages of Russia is considered in the article. Aims and Objectives The production rate of well can be increased several times by eliminating part of the perforated production string, as barriers to filtration processes in the bottomhole zone of the formation and increasing the filtration area due to the expansion of the bottomhole zone in the productive interval of the reservoir. In the article the technology and the tool allowing to improve a well during repair works are considered. Results Currently, the technology has been successfully implemented at 88 wells in the UGS facilities in Russia, resulting in a reduction in coefficients of filtration resistance, in increase in well productivity with a decrease in depression after the expansion of the wellbore in the interval of the productive reservoir.