Introduction. One of the key tasks of seismic exploration is to restore the distribution of properties across the section. This publication proposes a new method for predicting reflection coefficients from the input wave field. The availability of information about the change in reflection coefficients allows us to proceed to the estimation of the relative change in acoustic impedance across the section.

Goal. The aim of the work is to develop and test a new technology for estimating the relative change in acoustic impedance based on a wave field using an adapted Lasso regression method.

Materials and methods. To test the proposed approach, both synthetic data generated in the framework and real data obtained at one of the fields of Eastern Siberia were used.

Results. As a result of the conducted research, a new approach to solving the inverse problem of seismic exploration in an acoustic formulation is proposed. The developed algorithm has shown its effectiveness on real data, making it possible to improve the quality of the forecast of acoustic impedance in the section.

Conclusion. The results allow us to conclude about the effectiveness of the proposed approach. As a result of the application of the new technology, it was possible to increase the accuracy of the acoustic impedance prediction. 

Purpose. The CCUS (carbon capture, utilization and storage) agenda has an important role in preventing climate change caused by human activities. Technologies of carbon capture, utilization and storage are aimed at achieving zero net emissions. The implementation of CCUS projects makes it necessary to have geological formations of sufficient volume that are able to receive СО₂ and reliably contain it. The assessment of the geological potential of these formations should be approached comprehensively from the point of view of storage safety, considering all available data, and if there is not enough of them, an additional study program should be carried out.

Aquifers or depleted hydrocarbon deposits can be as objects for СО₂ storage. Regardless of the type of object, it is necessary to understand whether the reservoir is capable to receive СО₂, whether it will be securely trapped in the selected geological system, and what forces will provide this.

Materials and methods. As part of the implementation of a pilot project for the СО₂ storage, Gazpromneft-Orenburg LLC has identified promising facilities within the Eastern section of the Orenburg oil and gas condensate field, which currently look the most attractive from a geological standpoint. The assessment of the formations prospects was carried out by the methods of description, analysis, synthesis and 3D modeling based on 3D seismic data and well data (well logging and results, core data).

Results. This article gives a geological description of the East part of the Orenburg oil and gas condensate field. Results of exploration maturity analysis are presented, traps and their geological upside are identified, the criteria for the preservation of carbon dioxide in the selected pilot object is considered and analyzed, geological risks and uncertainties identification is fulfilled, and measures to remove them are proposed. Further tasks of the project are given.

Conclusion. The presented results allow us to make conclusions about the presence of a geological potential at the WU OOGCF for the СО₂ storage and compliance with the criteria for the preservation of carbon dioxide in the planned injection objects.

As part of the tasks for designing the development of promising areas in the oil and gas industry, a certain problem was identified with the inability to apply classical methods of geological modeling applying seismic-facial neural network prediction of reServoir propertieS of the reServoir according to SeiSmic data on the example of clinoform depoSitS of weStern Siberia analysis for the quantitative assessment of productive reservoir properties.

Consequently, attempts were made to test machine learning techniques and algorithms implemented in the specialized software IP_Seismic (IPLAB LLC).

Purpose. Main goal of the work was the development of projects for introducing new wells, calculating economic feasibility and profitability of financial expenditures based on a 3D geological model of the field.

Methods. The work used machine learning algorithms based on full-featured Kolmogorov functions implemented in the separate software IP_Seismic, as well as 3D geological modeling techniques in Petrel software.

Results. The outcome of the work resulted in the adjustment of the development program and the implementation of a certain number of business cases. Various typical examples of using machine-learning techniques are presented in this article, based on what additional wells for drilling, risk reduction programs, and the implementation of an alternative development system were proposed.

Conclusion. This work presents typical ways of finding promising drilling zones with neural network forecasting. The advanced mathematical basis laid down in specialized software, which was subsequently utilized in preparing the solution, is tested. Based on the developed methodology, examples of successful application of the approach for adjusting and designing operational drilling programs are presented, which can be replicated in other development projects.

Background. During the construction of the well, the casing strings are cemented. In turn, the quality of cementing is influenced by many factors, such as the flow rate, the casing standoff, the parameters of drilling mud and cement slurry, etc. In the case of poor-quality cementing, or the impact of cyclic loads, a violation of the integrity of the cement stone may occur, which in turn can lead to leaks in cement stone and the occurrence of sustained casing pressure (SCP). Prevention and elimination of SCP is a non-trivial task.

The aim of this article is to describe the factors affecting the quality of cementation, as well as the results of laboratory tests of an elastic self-healing cement system (SHC), which helps to prevent and eliminate SCP.

Materials and methods. Industry-specific methods of testing cement slurry and cement stone were used. Unique laboratory equipment was used to test the ability of cement stone to self-heal in contact with hydrocarbons.

Results. Self-healing of the cement matrix upon contact with hydrocarbons (oil, gas condensate) has been confirmed. The potential of using the SHC to prevent and eliminate intercolonial flows in case of violation of the cement matrix during the operation of the well is estimated.

Conclusions. The article describes the results of the actual laboratory testing of the SHC, as well as the potential of its application.

Aim. The aim of the research is to develop and approve the procedures for distributing the flows of the extracted product across the wells and the elements of the gas collection network, which is optimal in terms of the maximum gas condensate production criterion when fulfilling the task for the total gas extraction and restrictions on the allowable ranges of gas well flow rates.

The choice of operating modes for gas and gas condensate wells and the distribution of production flows through the gas collection network are interrelated tasks, which require their coordinated solution. The implication of the proposed models and algorithms is aimed at fulfilling this condition.

Materials and methods. The proposed optimization algorithms are non-linear programming methods.

Procedures for approximating functions of one variable are connected to the optimization algorithms.

Results. The proposed models and algorithms are based on the decomposition of the original general model, consisting of four levels: wells, clusters, general cluster gas pipelines and a complex gas treatment plant. Firstly, this makes it possible to perform calculations separately for each level. Secondly, the solution of a problem with a large number of unknown variables at each level is replaced by the solution of a series of problems, each of which contains a smaller number of unknown variables. This makes it possible to perform optimization of real infield gas gathering networks. The algorithms not only search for the values of the required variables, but also plot the dependences of the well flow rates for gas condensate on the well flow rates for gas, as well as gas condensate flow rates on gas flow rates for each element of the gas gathering network.

Conclusions. The calculations performed have showed the possibility of increasing the condensate withdrawals at a constant level of total gas extraction with the use of the proposed models and algorithms. A subsequent check based on integrated modeling has showed that there were no technological complications in the gas gathering system when the optimum scenario was implemented.

Background. At the moment hard-to-recover reserves in company portfolio of Gazpromneft are about 60–80 %. The low-permeable reservoir development is produced using hydraulic fracturing. It is required to assess risks both at the beginning and in the process of reservoir development to select correct wells operation and reservoir development. This can be accomplished only by regularly well test. Well tests monitor parameters, and also their changes.

Aim. Integrated analysis of hydrodynamic characteristics (reservoir pressure, transmissivity, fracture half-length, injectivity profile) for low-permeability reservoir, which influence development field. Analysis was made using pressure transient analysis (PTA) and production logging tools (PLT) using different time studies.

Materials and methods. Initial data of PLT and PTA, daily injection rates and tubing head pressure. Tubing head pressure was calculated on the top depth of perforations intervals. In addition the authors used well log interpretation results and PVT-properties.

Interpretations PTA and PLT were carried out using standard methods and analytical models. The author gives a detailed description further in the text.

Results. Injectivity index behavior based on conducted analysis is non-typical sometimes: increase fracture halflength and injectivity index despite injection rate and bottom hole pressure (BHP) aren’t changed. The effect is related reservoir pressure and its change in the drainage area. It is may lead to water breakthrough through fractures (increasing fracture of injection well in direction to production well).

Conclusions. The authors consider complex interpretation well test at different time on the pilot project. The results can to substantial influence field development system. In this connection there is a need to create special programs of regular well tests to find correct production and injection wells operation, and as a result, increase the displacement efficiency and oil recovery factor. Significance of regularly well test increases because of their influence of reserve recovery. Due to different effects which are shown up PTA and PLT under stable well performance. This is particularly important for oil industry and Gazpromneft because hydrocarbon reserves of the low-permeable reservoir preponderate.

Aim. The purpose of the present work is to develop a method for estimation influence of hydraulic pressure losses in horizontal gas wells on productivity. Tasks to be solved are the development of an analytical model that describes the effect of hydraulic pressure losses along horizontal wellbore on the productivity distribution, determination of the main dimensionless factors describing process, solution for pressure distribution along a horizontal wellbore and generalization of solution in graphical and analytical correlations form.

Matherials and methods. The process in question is described by the analytical mathematical model consisting of differential equations in dimensionless form. Equations are solved numerically, solution is presented in graphical and analytical correlation form.

Results. Influence of hydraulic pressure losses in horizontal wellbore on productivity described by adjusting the coefficient “b” of nonlinear part of gas well inflow equation. Main factors influencing on “b” value is dimensionless length of horizontal wellbore, dimensionless nonlinearity factor of well inflow, exponent on Reynolds number in liner friction law. Value of coefficient “a” of linear part of gas well inflow equation does not depend on hydraulic pressure losses in a horizontal wellbore.

Conclusions. The results of the work can used for estimation the productivity of horizontal gas wells taking into account hydraulic pressure losses in a horizontal wellbore, for estimation influence of hydraulic pressure losses on productivity and to estimate the optimal length and diameter of a horizontal wellbore liner, as well as in simplified analytical integrated models of gas field development.

In this paper methods for predicting efficiency of different geological and engineering operations on wells are presented.

The purpose of the work was to determine the optimal ways for evaluation of planned flow rates after geological and engineering operations and comparative analysis economic efficiency of such operations.

Materials and methods. Key parameter for such evaluation is productivity index, its prediction method depends on the type of geological and engineering operations. This work describes two methods of productivity index determination: numerical and theoretical. Theoretical methods determine theoretically possible productivity by formulas which are reflecting physic processes in formation. Numerical methods are used to analyze actual well performance, what allows to determine potential productivity. There were three time series analysis methods examined as numerical methods and the one, that allows more accurately determine potential productivity index according to actual data, was chosen.

Result of this work is a possibility to calculate planned effects of geological and engineering operations such as perforation work, bottom-hole treatment, hydraulic fracturing, and determine which one is the most economically practical for wells.

Conclusion. Methods and automated instruments, which are using these methods as foundation, are successfully used to determine wells for well intervention processes and planning geological and engineering operations for East-Messoyakha formation.

Background. The paper describes a study of injection-induced fractures propagation with special well testing. It also concerns diagnostics of fracture opening and its trajectory.

There’s a lot of approaches to diagnosing injection-induced fractures, including IPR tests and pressure transient analysis: the presence of the fracture can be robustly determined. Although, the question of fracture geometry: if it opens mostly laterally or grows vertically connecting other reservoirs — is open. The lateral fracture growth may be good for oil displacement, e.g. in linear waterflood systems oriented along the regional stress. At the same time, there’s a risk of direct water breakthrough into producing wells, sometimes located miles from injectors [1].

Another substantial risk is fracture vertical propagation: connecting different reservoirs to injection can seriously and negatively affect the development [2, 3].

Fracture height can be successfully assessed with cased hole logging, but the success depends on the well trajectory. Even slight inclination creates a distance between a well and a fracture (mostly strictly vertical), growing further from the fracture initiation point. As a result, “behind-the-casing” sensors, such as noise and temperature, lose the informational capacity of seeing the fracture flow and injection into other reservoirs. That’s why diagnosing fracture vertical growth and its half-length is very important and relevant.

The goal of the study is to justify and test the well testing diagnostic routine to assess fracture geometry. The objectives are to:

• build a fracture propagation model;
• justify the well test program;
• test the program on the actual well;
• interpret the results and match them in the model.

Materials and methods. The diagnostic routine is based on a specially designed numerical-analytical model. The current state of the fracture (half-length, thickness and pressure profile) is being determined with a triple-linked calculation of fluid diffusion, fracture hydraulics and geomechanics.

Results. The result of the work is a field test, which successfully determined the fracture geometry and was matched in a model.

Conclusion. The paper justifies the special well-test based diagnostic routine and interpretation approach for assessing the injection-induced fracture geometry and the.

The skin factor is an important indicator characterizing the filtration and reservoir properties of a formation in the near-wellbore zone. The reliable information about its values comes from the interpretation of hydrodynamic studies under non-stationary filtration regimes. However, due to various reasons, this type of research is not always feasible for determining the properties of a porous medium in both wellbore and distant areas of the reservoir. In such situations, indirect methods for assessing the skin factor become particularly relevant.

Objective. To determine the skin factor of producing horizontal wells in conditions of limited high-quality initial information.

Materials and methods. The study used materials from production hydrodynamic studies under stationary and non-stationary filtration regimes and their interpretation results. The methods of mathematical statistics and graphical analysis were applied to process the data.

Results. A correlation was discovered between the skin factor and a complex parameter equal to the pressure drop in the skin zone divided by the flow rate of the well before it stopped for testing. The study provides calculations and their comparison with the actual skin factor levels. The features of the relationship between relative productivity and the magnitude of the skin effect manifestation are discussed.

Conclusion. The presented methodological approach allows for obtaining adequate skin factor estimates, which can be used to solve various oilfield tasks.

Introduction. For massive carbonate reservoir with high vertical permeability and underlying water, coning of bottom water is a necessary part of development process. As an example, the way for water coning prevention using thermogelling composition for Zapadno-Hosedauskoe field is described.

Aim. The aim of investigation is planning and realization of water coning prevention pilot project. It is also necessary to determine well candidate criteria, to analyze first results, and to look for technology optimization variants.

Methods. For coning evaluation Chan’s diagnostic plots and well flow profile were used.

Results. The pilot project has been realized in three steps, based on first step results the additional well candidate criteria has determined and methodology basis for candidate search and treatments planning has developed. During second step, treatment volumes have been varying, in third step, alternative composition has been approved and repeated treatments have been done. In 2019–2022 years period 26 treatments were done, all except one were successful, oil rate increment and watercut reduction were obtained. Additional oil production due to pilot project realization is more than 120 000 tons.

Conclusions. Authors showed results of three years water coning prevention treatments pilot project, determined success well candidate criteria and estimated additional oil production.

Aim. In order to increase the forecast indicators of oil production using an analytical approach in conditions when the flow of fluid to a horizontal well cannot be described by Darcy’s linear filtration law, an estimation technique using a nonlinear filtration law has been developed.

Materials and methods. using mathematical modeling, the functional dependence of the flow rate of a horizontal well drilled in a low-permeability reservoir on the nonlinear filtration law was derived. A stable mathematical solution has been found that makes it possible to use the “gluing point” — the transition zone from linear to nonlinear flow.

Results. The article proposes a fluid filtration model that takes into account the influence of inertial forces (and, as a consequence, the change in the modulus of the fluid flow velocity) and solves a system of three nonlinear equations for three unknown functions (the pressure function in the reservoir and two components of the velocity vector). In comparison with the existing equations, the model proposed by the authors most reliably describes the dynamics of the production well in the oil field under consideration with low reservoir permeability.

Conclusion. Fluid filtration to a horizontal well in a low-permeable reservoir is accompanied by high values of surface friction between the rock skeleton and the filtered fluid, which leads to a violation of Darcy’s linear law. Most of the existing models do not take into account the nonlinearity of fluid filtration in low-permeable reservoirs, which leads to significant errors in the forecast of technological performance of the producing well, and, in particular, the flow rate of the well for oil. The developed technique allowed to increase the accuracy of predictive analytical calculations by taking into account nonlinear effects. 

Introduction. Rotary steerable systems (RSS) allow to drill longer horizontal section, reduce risks and drill faster. Some Russian companies work on RSS creation, however it will take for a while till start of RSS commercial production.

Difficulties with the supply of RSS are forcing a reconsideration of the horizontal drilling approach. RSS availability on the market has led to wide RSS implementation, even when RSS was not the only available option, when lower tier technology — downhole motors (DHM) could be used.

Objective. Such topics as technical possibility of drilling with DHM, potential risks and economical effect are described in the article.

Methods. In order to make proper decision on replacing RSS with DHM that is necessary to estimate technical possibility, potential risks and economical effect.

Results. Technical possibility of drilling with DHM should be estimated by using special software, but the software can’t take in account such factors as stiffer pipes in high dogleg severity intervals, azimuth turn, reverse horizontal displacement and others. That’s why the local experience is also very important and should be taken in the consideration.

Apart from the technical possibility, such potential risks as wellbore quality, hole cleaning, differential stuck of bottom hole assembly (BHA), pack off BHA, sensors offset also should be assessed.

Background. At the Eastern part of the Orenburg oil and gas condensate field, which deals with abnormally low stratum pressure and high reservoir fracturing, special attention is given to controlling the absorption of technological well-killing compositions by a reservoir. Additional problems such as high gas-oil ratio (GOR) and high hydrogen sulphide content restrict the choice of blocking compositions and killing technologies. Standard methods for selecting blocking compositions do not allow one to identify effective well-killing technologies for the described conditions unambiguously. Identifying the blocking composition properties that influence the efficiency of well killing in complicated conditions of the Eastern part of the Orenburg oil and gas condensate field will help reduce the risks of accidents, increase the effectiveness of well-killing operations, and improve the project’s economic performance.

Aim. This work aimed to determine the main factors of laboratory studies which affect the efficiency of technological blocking compositions for killing wells in the conditions of the Eastern part of the Orenburg oil and gas condensate field.

Materials and methods. The laboratory analysis involved testing a range of blocking agents in conditions closest to reservoir ones. The physicochemical and rheological characteristics of blocking compositions were compared, as well as their effect on the productive properties of a formation. Laboratory tests were carried out on blocking compositions’ physicochemical, rheological and filtration characteristics.

Results. The results of laboratory and pilot tests were compared with the data about the primary blocking compositions appliance at the Orenburg oil and gas condensate field.

Conclusion. On the basis of the study, a hypothesis was put forward about the dependence of the killing wells blocking composition effectiveness in complicated conditions of the Orenburg oil and gas condensate field depends on its physical and chemical parameters, effective viscosity values and an indirect indicator of the composition strength.

Flow rate is one of the key parameters used by the company’s services. The measuring equipment is integrated with automated process control systems in data transmission. However, due to the growing well stock and the increasing number of measurements (including measurements for HTR-reserves’ (hard-to-recover reserves) wells), the process of analyzing and validating lcmeasurements began to require significant human resource contribution. The well metering quality management tool was developed to reduce the time for data processing and to strengthen control.

The aim of this work is to describe the practical experience of implementation and using a special software package for quality management of well flow measurements.

Materials and methods. The well flow measurement quality management tool is an intermediate link between a well and a commercial hydrocarbon accounting system. It performs the function of filtering the data with automatic verification of its parameters. The tool for monitoring well metering allows us to integrate measurement data, laboratory data, well operation parameters and equipment into one system.

Results. Implemented algorithms for calculations and automatic validation of measurements as well as system’s business rules have allowed to reduce time spent on validating flow rates and watercut by 70 %, and to eliminate negative human impact. The tool for data quality management and the special module have significantly reduced the non-production time of analytics (for searching, collecting, recording and analyzing the parameters of the well and the equipment), strengthening control over the wells metering.

Conclusions. All the completed improvements made it possible to use the incoming data as efficiently as possible, to quickly respond to changing operating modes of wells.

Background. It is impossible to minimize and prevent accidents during the operation of oilfield and drilling equipment without the use of non-destructive testing. Special attention is paid to the detection of surface defects by magnetic powder and capillary methods of non-destructive testing.

Aim. The article compares the applied methods of magnetization of control objects and the application of a magnetic indicator during magnetic powder control in the oil industry with the railway transport industry. An overview of operational defects of various parts detected by magnetic powder and capillary methods of nondestructive testing is given. Photographs with indicator drawings (traces) of defects detected by magnetic powder and capillary methods are shown.

Materials and methods. Based on the experience of conducting magnetic powder and capillary methods of nondestructive testing, the article discusses the various defects found, most often encountered in practice during the operation of oilfield and drilling equipment.

Results. The technology of conducting magnetic powder and capillary control in field and workshop conditions of oilfield and drilling service enterprises is described. The main types of capillary control used and methods of applying flaw detection materials are shown. Photographs of defects of various parts are presented with a description of the advantages of using a particular method in certain conditions affecting the sensitivity of the control.

Conclusions. The advantages and disadvantages of each of the methods are given based on the experience of using various means of non-destructive testing.

The aim of this study is to develop and apply an autonomous approach for predicting the probability of hydrocarbon reservoirs spreading in the studied area.

Materials and methods. The prediction was made based on the 3D seismic survey data and well information on the early exploration stage of the studied field. The results of the lithological interpretation of logging from nine wells were used, four of which penetrated the object vertically or subvertically, while the remaining five were drilled horizontally through different stratigraphic parts of the Achimov sedimentary complex, which is the object of this study. The paper presents an approach based on a technological stack of machine learning algorithms with the task of binary classification and modification of the geological-geophysical dataset. The study includes the following sequence of actions: creation of data sets for training, selection of features, reverse-calibration of data, creation of a population of classification models, evaluation of classification quality, evaluation of the contribution of features in the prediction, ensembling the population of models by stacking method.

As a result, a prediction was made — a three-dimensional cube of calibrated probabilities of belonging of the studied space to the class of reservoir and its derivative in the form of the map of effective thicknesses of the Achimov complex of deposits was obtained. Assessment of changes in the quality of the forecast depending on the use of different data sets was carried out.

Conclusion. The reverse-calibration method proposed in this work uses the uncertainty of geophysical data as a hyperparameter of the global tuning of the technological stack, within the given limits of the a priori error of these data. It is shown that the method improves the quality of the forecast. The technological stack of machine learning algorithms used in this work allows expert-independent generalization of geological and geophysical data, and use this generalization to test hypotheses and create geological models based on a probabilistic view of the reservoir. The approach, formalizes the generalization of data about the target, using only factual information such as lithology along the wellbore and seismic data. Depending on the input data, the approach can be a useful tool for finding and exploring geologic targets, identifying potential resources, and optimizing and designing reservoir development systems.

Background. In most cases, the 3D Hydrodynamic Model (3HM) of a field is used to choose an optimal development system. Despite of high level of detail and accuracy of the model, significant computational resources and time are required to create and apply the 3HM. Therefore, the task to reduce the resource expended on project decisions making while minimizing the loss in the quality is relevant.

Aim. The approach proposed to optimize the existing methods for solving the problem of choosing optimal parameters of the development system is to make the rapid assessment of NVP and КИН based on multivariate modeling using a Hydrodynamic Two-Dimensional simulator and sensitivity analysis with machine learning methods under conditions of geological uncertainty.

Materials and methods. A Hydrodynamic Two-Dimensional simulator is used to solve the problem of choosing optimal parameters of the development system. Machine learning methods based on the Python programming language are used to process, visualize and conduct sensitivity analysis of the results.

Results. The algorithm of choosing optimal parameters of the development system based on multivariate modeling using machine learning methods is proposed. The analysis of the sensitivity of oil recovery factor and NPV to changes in the input parameters of the model was carried out. Based on the results, a three-dimensional matrix of results was created. The matrix of results allows selecting the optimal density of a well pattern using the triple values of the effective reservoir thickness, permeability and length of the horizontal section. The practical significance of the matrix of results lies in the possibility of forming a hybrid project grid of wells in clustering zones according to the values of permeability and effective reservoir thickness. Also, the matrix helps to adjust project decisions for choosing optimal parameters of the development system under conditions of geological uncertainty in a short time.

Conclusion. Based on multivariate modeling, the alternative approach for choosing combined grids using machine learnin’g methods is proposed to field development planning.