bluuebunny/crossref_metadata_2025 huggingface dataset:
Problem of Gas Breakthrough Solved through Installation of Recompletion Assembly with Autonomous Gas Inflow Control Devices AGICD in Oil Producing Wells
Authors: Ivanova Ekaterina Yurievna , Khokhlov Danil Igorevich , Shangin Andrey Viktorovich , Nesterov Pavel Vladimirovich , Britov Evgeniy Vitalevich , Arzamastsev Georgiy Georgiyevich
Published: October 2021

During the field tests in oil producing wells at the Verkhnechonskoye field there were autonomous gas inflow control devices (hereinafter referred to as AGICD) applied for the first time as part of a recompletion assembly.

The recompletion technology is based on a well completion design solution with AGICD which consists in dividing the liner into intervals, equalizing the total inflow and restriction of the inflow of adverse fluids in producing wells with increasing flowrates of adverse fluids as well as wells shut in due to water/gas breakthroughs.

The recompletion assembly is run into the previously lowered liner equipped with sand screens and divided into several zones by swellable packers.

The new assembly essentially features the classical completion assembly but comprising original 73-mm-tubing-based equipment such as a shoe, cup packers, a packer hanger, and centralizers. The equipment design allows for its complete retrieval if necessary. Since oil contains a lot of solids and deposits of asphalts, resins, and paraffins, the recompletion assembly has a flush valve enabling acid cleanout of the pay zone of the formation during the operation.

In order to prepare for the recompletion assembly to be run in, intense analytical work was done to study the candidate wells and geological conditions and peculiarities of the Verkhnechonskoye field, to analyze the open hole logging data and the oilfield geophysics vs. its hydro-dynamic model data.

During the field trials, recompletion assemblies were run in two wells of the Verkhnechonskoye field and monitored to assess their operation with AGICD within a set period of time. Then the equipment was pulled out and the wells were monitored again without AGICD. The findings provided the basis for the assessment of the equipment operation.

The analysis of the trials results showed that the equipment is prepared, run in the hole and retrieved in normal mode. The qualitative AGICD performance indicators are based on the stable well operation within the total nonfailure operating time after the recompletion assembly is run in the hole. The quantitative AGICD performance indicators are defined by the achieved gas ratio decrease and oil flowrate rise.

The trials also confirmed the convergence of the AGICD expected and field-proven performance indicators which makes it possible to plan precisely well operation modes when using recompletion equipment.

The trials findings prove that the recompletion technology is reasonable for wells with high rates of non-targeted fluids as well as idling wells (due to water/gas breakthrough) to make them active again.
Using DNA-Logging to Determine Inflow Profile in Horizontal Wells
Authors: Posdyshev Arsenii Stanislavovich , Shelyakin Pavel Vladimirovich , Shaikhutdinov Nurislam Maratovich , Popov Aleksey Alekseevich , Logacheva Maria Dmitrievna , Tutukina Maria Nikolaevna , Gelfand Mikhail Sergeevich
Published: October 2021

The purpose of this work is to adapt and apply Next Generation Sequencing methods in oil and gas well field studies. Relatively recent NGS methods provide a description of a geological formation by analyzing millions of DNA sequences and represent an entirely new way to obtain information about oil and gas reservoirs and the composition of their fluids, which could significantly change the approach to exploration and field development.

We present the results of pilot work to determine the inflow profile in a horizontal well based on DNA markers. The technology is based on the comparison of bacterial DNA from drill cuttings obtained while drilling with DNA from microorganisms of fluids obtained during production at the wellhead. Because of their high selectivity, individual microbes live only under certain conditions (salinity, oil saturation, temperature) and can be used as unique natural biomarkers. The comparison of DNA samples of drilling cutting and produced fluid allows for identification of the segment of the horizontal well from which the main flow comes, as well as identifying the type of incoming fluid (water, oil, gas) without stopping the operation process and without conducting expensive downhole operations.

As a result of these studies, the microbial communities of the oil-bearing sands and formation fluids of the Cretaceous deposits (group BS) in Western Siberia were identified, and the relative numerical ratio of microorganisms in the formations was determined. It was shown that the microbiome diversity changes with depth, and depends on the lithological composition, and sequencing data obtained from cuttings samples correlate with data from wellhead samples of produced fluid. Thus, the practical applicability of DNA sequencing for solving field problems in oil and gas field development, in particular for determining the inflow profile in horizontal wells, was confirmed.
Restoration of Seismic Data Using Inpainting and EdgeConnect
Authors: Radosavljevic Marko , Naugolnov Mikhail , Bozic Milos , Sukhanov Roman
Published: October 2021

Missing seismic data is largely present problem in the world. Lack of seismic data usually occurs due to some form of natural obstacle or legislative prohibitions of seismic exploration. Restoration of seismic data would allow locating of new oil traps and reduce the risk of unsuccessful drillings. The approach is based on deep learning (image inpainting) techniques, which will be applied on inline and crossline sections of a given 3-d seismic cube, in order to restore missing parts of sections. The study was provided for non-commercial purpose for the aims of scientific research. Data used in our experiments comes from open source typical Western Siberia field. Our approach uses Generative Adversarial Networks (GANs) for completing missing parts of images (sections), based on known parts. Method can be used for restoration of arbitrarily-shaped missing parts of seismic cube, but also for extrapolation purposes. Metrics used for model evaluation are correlation coefficient and mean absolute percentage error (MAPE) between original and inpainted parts of data.

This paper applies modern approach from growing image inpainting field to restore missing data, even if it's irregularly-shaped and very large. Using very powerful GANs is what gives this model ability to learn difficult inpainting scenarios, but also implicates challenging and time-consuming training process. Accurate estimation of model performances in different scenarios provides an exact instruction manual for a geologist, which helps him to identify cases where our model should be applied.
Digital Slot: A Tool for Optimization and Development of New Hydraulic Fracturing Technologies
Authors: Idimeshev Semen Vasilievich , Isaev Vadim Ismailovich , Tikhonov Alexey Alexandrovich , Semin Leonid Georgievich , Bannikov Denis Viktorovich , Velikanov Ivan Vladimirovich , Ivanov Maxim Grigorievich , Kuznetsov Dmitry Sergeevich , Belyakova Ludmila Sergeevna
Published: October 2021

We present the digital slot — a tool for the development of new hydraulic fracturing technologies via digitization of slurry flow in narrow channels. We consider slurry containing fluid, proppant, and fiber components. The flow is described by a continuum mathematical model based on the lubrication theory. The numerical algorithm utilizes Lagrangian approach with finite volume pressure solver. We present the results of laboratory validation and simulation examples showing the key effects affecting solids transport in hydraulic fracturing: settling, bridging, gravity slumping, materials degradation, viscosity contrast, and bank formation.
A Case Study for the Development and Use of a Well Control Simulator as a Digital Twin of a Real Scenario
Authors: Curina Francesco , Talat Qushchi Ali , Aldany Ahmad
Published: October 2021

Simulators in the petroleum industry have been used mainly for training purposes even though they present different applications like digital twins. In this regard, a simulator must approximate the well environment to reflect operative actions and reactions. This paper describes a case study where a well control simulator has been developed to be used as a digital twin where operators may try different scenarios in a safe environment before applying them to the physical well.

To cover all aspects of the operation, the simulator should simulate surface equipment as well as a downhole environment. Numerical modeling techniques and hydraulic simulators are used to design the well response to operations. Different scenarios were established to cover most of the possible downhole problems and equipment malfunctions including electrical and hydraulic failures. The study compares a pre-determined set of KPIs common to three different types of simulation: well control, procedural and an integration of both.

The target of the study is to collect the data resulting from the use of the simulator while it replicates a real-life situation. This virtual model of the rig and the well can be used to calibrate the main drilling parameters like SPM, RPM and WOB. The digital twin is also used to optimize operational procedures and improve performance and efficiency of rig crews as well as reduce their response time to possible problems.

The results show an increase in performance when the knowledge of the rig is combined with the downhole feedback experience. This proves that training of the crew by reproducing their own equipment allows for a major jump in readiness and faster response with minimal mistakes.

In addition, conducting the operation virtually allows the crew to uncover any possible issues before tackling the physical well. This in turn helps to reduce errors and safeguard both well and equipment integrity.

This paper discusses the integration of the use of downhole environment behavior into a complete digital twin which will play an important role for providing a source of data for regular case studies concerning well control, Maintenance, Scheduling and other critical decisions. This new method candidates itself as a major contender for the future of simulation in the drilling business and shows the importance of that for reducing risks and errors.
Field Development Optimization Using Machine Learning Methods to Identify the Optimal Water Flooding Regime
Authors: Timonov Alexey Vasilievich , Shabonas Arturas Rimo , Schmidt Sergey Alexandrovich
Published: October 2021

The main technology used to optimize field development is hydrodynamic modeling, which is very costly in terms of computing resources and expert time to configure the model. And in the case of brownfields, the complexity increases exponentially.

The paper describes the stages of developing a hybrid geological-physical-mathematical proxy model using machine learning methods, which allows performing multivariate calculations and predicting production including various injection well operating regimes. Based on the calculations, we search for the optimal ratio of injection volume distribution to injection wells under given infrastructural constraints.

The approach implemented in this work takes into account many factors (some features of the geological structure, history of field development, mutual influence of wells, etc.) and can offer optimal options for distribution of injection volumes of injection wells without performing full-scale or sector hydrodynamic simulation.

To predict production, we use machine learning methods (based on decision trees and neural networks) and methods for optimizing the target functions.

As a result of this research, a unified algorithm for data verification and preprocessing has been developed for feature extraction tasks and the use of deep machine learning models as input data.

Various machine learning algorithms were tested and it was determined that the highest prediction accuracy is achieved by building machine learning models based on Temporal Convolutional Networks (TCN) and gradient boosting.

Developed and tested an algorithm for finding the optimal allocation of injection volumes, taking into account the existing infrastructure constraints. Different optimization algorithms are tested. It is determined that the choice and setting of boundary conditions is critical for optimization algorithms in this problem.

An integrated approach was tested on terrigenous formations of the West Siberian field, where the developed algorithm showed effectiveness.
Development of Deep Transformer-Based Models for Long-Term Prediction of Transient Production of Oil Wells
Authors: Abdrakhmanov Ildar Radikovich , Kanin Evgenii Alekseevich , Boronin Sergei Andreevich , Burnaev Evgeny Vladimirovich , Osiptsov Andrei Aleksandrovich
Published: October 2021

We propose a novel approach to data-driven modeling of a transient production of oil wells. We apply the transformer-based neural networks trained on the multivariate time series composed of various parameters of oil wells measured during their exploitation. By tuning the machine learning models for a single well (ignoring the effect of neighboring wells) on the open-source field datasets, we demonstrate that transformer outperforms recurrent neural networks with LSTM/GRU cells in the forecasting of the bottomhole pressure dynamics. We apply the transfer learning procedure to the transformer-based surrogate model, which includes the initial training on the dataset from a certain well and additional tuning of the model's weights on the dataset from a target well. Transfer learning approach helps to improve the prediction capability of the model. Next, we generalize the single-well model based on the transformer architecture for multiple wells to simulate complex transient oilfield-level patterns. In other words, we create the global model which deals with the dataset, comprised of the production history from multiple wells, and allows for capturing the well interference resulting in more accurate prediction of the bottomhole pressure or flow rate evolutions for each well under consideration. The developed instruments for a single-well and oilfield-scale modelling can be used to optimize the production process by selecting the operating regime and submersible equipment to increase the hydrocarbon recovery. In addition, the models can be helpful to perform well-testing avoiding costly shut-in operations.
Application of Integrated Asset Modeling Approaches for Reservoir Management of a Large Oil Field in Western Siberia
Authors: Koshkin Timur Aleksandrovich , Sayfutdinov Azat Firdavisovich , Kukushkin Viktor Aleksandrovich , Markov Pavel Vladimirovich
Published: October 2021

The article reviews the development and implementation of a digital twin for one of the large fields of LUKOIL-West Siberia LLC. The project team has developed an integrated asset model (IAM) of an oil field at a late stage of its development, which is used both for making managerial decisions and in the operational work of the engineering and technical service. The IAM includes simplified models of reservoirs, models of wells and gathering systems, as well as simplified models of plants. The resulting model can produce short-term assumptions regarding production levels (up to 1 year) and is highly sustainable, which is confirmed by the examples given in this article as to the application of IAM for various production tasks. The developed automated tools allow making prompt decisions to optimize well stock operation, as well as to reveal deviations in the process parameters of downhole pumping equipment and metering facilities. The use of IAM tools enable production functions to perform many application tasks related to forecasting well operation modes and evaluating the existing production capacities of the field. The cases presented in this paper serve as a good practice for application of the IM by assets in their activities and can be implemented for similar brownfields.
Creating the Integrated Model for Conceptual Engineering of Reservoir Management and Field Facilities Construction – Experience of Tazovskoe Oil and Gas-Condensate Field.
Authors: Varavva Artem Igorevich , Apasov Renat Timergaleevich , Samolovov Dmitry Alexeyevich , Elesin Artem Viktorovich , Apasov Gaidar Timergaleevich , Voyevoda Evgeniya Vladimirovna , Reshetnikov Dmitry Anatolevich , Senachin Maxim Arkadievich
Published: October 2021

The paper describes the experience of building a full-field integrated model (PK1 reservoir) of the Tazovskoye field, including a model of the reservoir, wells, and a gathering network, taking into account the external transportation system. In order to integrate the features of the field, such as the simultaneous development of a thin oil rim and a gas cap, high growth rates of the gas-oil ratio, oil wells - both ESP-operated and flowing, algorithms and tools have been developed, which are discussed in the paper. The results of the integrated model runs are given, main features of the solutions are highlighted.
Experience in Optimizing the Location and Parameters of Multistage Hydraulic Fractures for a Multilateral Well Based on Reservoir Simulation
Authors: Syrtlanov Vil , Golovatskiy Yury , Chistikov Konstantin , Bormashov Dmitriy
Published: October 2021

This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).
Methodology for Constructing Simplified Reservoir Models for Integrated Asset Models
Authors: Markov Pavel Vladimirovich , Botalov Andrey Yuryevich , Gaidamak Inna Vladimirovna , Smetkina Margarita Andreevna , Rychkov Andrey Fyodorovich , Koshkin Timur Aleksandrovich
Published: October 2021

The paper presents the developed methodology for building simplified reservoir models for integrated asset models (IAM) of oil and gas fields: allocation and substantiation of areas, substantiation of model parameters, substantiation of actual weighted average reservoir pressure for areas, history matching and validation, evaluation of effective injection factors, integration in an IAM, prediction calculations, model updating. The novelty of the methodology is the developed approaches and methods of considering different features of fields with a high extent of automation for areas and fields as a whole. Models based on the material balance method and two-dimensional proxy models of one-phase flow in porous media are used as simplified reservoir models in the paper.

The developed methodology has been successfully tested for four oil and gas fields of Russia, which have different geological and production features: a large field with a long development history and a large number of active wells, a field with low permeability in all pay zones and high scopes of new wells commissioning, a field with a gas cap and high gas/oil ratios (GOR) for individual wells, a field with a complex system of reservoirs and tectonic faults and a large number of multi-pay production wells.

For three out of four fields, at the moment, the IAMs have been transferred to commercial operation based on the pilot projects performed and are used by field specialists to solve the following problems: quality analysis of reservoir pressure measurements; assessments of actual reservoir pressure trends by areas; assessments of ineffective injection for areas; prediction of reservoir pressure, water cut and GOR profiles for wells (up to one year) for various prediction scenarios, including optimization scenarios (taking into account the limitations of the material balance method).
Approach to Hydrodynamic Modeling of In-Situ Combustion in Carbonate Reservoir Based on the Results of Laboratory Studies and Preliminary Works for Pilot Test
Authors: Maksakov Kirill Igorevich , Lesina Natalia Valerievna , Schekoldin Konstantin Aleksandrovich
Published: October 2021

For the purpose of this work, the authors used an integrated approach to the modeling of in-situ combustion (ISC) including the results of laboratory studies and preliminary works, which significantly affect the choice of the method for implementing ISC and the results obtained in the process of modeling.

The laboratory studies provided the data on the temperature range of the beginning of high-temperature oil oxidation, which is to be achieved during the modelling of the bottomhole zone heating. Based on the resulting injectivity profile, the reservoir distribution within the injection well zone in the geological model was updated. A high-permeability channel between the injection well and one of the production wells revealed during cold water injection explains the main oil production increment resulting from ISC and demonstrated by the reservoir simulation model. Based on the results of model runs for a more uniform distribution of the effect between producing wells, the best start-up time for the most reactive well was determined. Using dynamic modeling of in-situ combustion in a carbonate reservoir, the parameters of this technology implementation were found, and incremental oil production was estimated.

For the first time, the ISC technology is planned for implementation in a carbonate reservoir with high-viscosity oil in Samara region. The developed integrated approach to the dynamic modeling of in-situ combustion, which considers both the laboratory studies and preparatory work data, enables the most accurately determination of the best ISC technological parameters and this technology contribution.
Practical Application of Integrated Simulation Technologies for Asset Development and Surface Facilities Design of Gas Fields
Authors: Zhuravlev Mikhail , Novikova Anastasiia , Cherkasova Aleksandra , Shakhov Dmitry , Kharkovsky Alexander , Belousov Roman , Sadykov Azamat , Anuchin Konstantin , Avanesyan Grisha , Khafizov Vadim
Published: October 2021

The main goal of this paper is to describe the automation process for asset design solutions assessment in accordance with the expected production levels in dynamics. The integrated model contains embedded sub-models (various assessment elements, such as pipeline networks, compression facilities, gas treatment units, reservoir simulation models for production profiles simulation and an economic model to obtain an instant investment estimate).

A continuous data flow between all the component models provides a quick assessment of different variables influence on the final efficiency of the integrated asset development option; this approach makes possible the rapid expansion of options range as well as the increase in analysis depth.

We describe this approach on the example of the gas assets group development project, which includes the integration of following part of surface facilities: pipeline networks (gathering system) for well pads with the corresponding booster compressor stations and transport network to deliver well product to gas process unit. The work shows the recommendations about how to set up the optimal configuration of an integrated model (type and composition of sub-models, linking algorithms, data exchange directions, etc.) to solve various issues of long-term planning. In addition, we show the example of standardizing the process of managing the sub- models to provide the integrated model fast update when new production data arrives or when the surface facilities concept is changed and to make the approach transfer to other close projects easier.

The novelty of the work lies in the creation of a unique approach to solve the issues of conceptual design by flexible configuration of an integrated model for specific tasks. This approach includes processing of production data different formats, the ability to connect an economic model to obtain the instant investment assessment of surface facilities option within comprehensive analysis. In addition, it includes the ability to connect detailed models of the gas-processing unit and booster compressor station with prospective economic efficiency assessment in accordance with the production profiles updates.

The integrated model example and overall approach that we provide in this paer is unique due to the following factors:

– "flexibility" of the model, which changes its appearance depending on the tasks. – prompt update of the economic indicators of the project. – clear accounting of transport and process facilities (use of detailed models for pipeline and processing systems (including booster compressor stations).
Full Integrated Model as a Tool for Strategy Evaluation of the Greenfield
Authors: Platon Denis Nikolaevich , Gatin Aidar Ramilovich , Fomin Matvei Nikolaevich , Korostelev Nikita Sergeevich
Published: October 2021

The main goal of this work is to evaluate and select the best strategy for the development of the field in the first stage of development. To solve this problem, a full-scale integrated model was created that takes into account the physics of the reservoir, wells and surface infrastructure, as well as their mutual influence. The integrated model was calculated for the full development of the asset.

The integrated model of the A. Zhagrin field is based on three simulation models, well models and surface infrastructure, which are linked through an integrator program. All constituent parts of the model are configured to accurately reproduce their actual operation.

Greenfield is characterized as active drilling, so the planned well count is modeled by replacing wells with "typical" well models, which are selected by taking into account the expected input flow rate, well design, well completion and well trajectory. Fields of the first stage of development are characterized by limitations related to oil transportation and treatment. These constraints are also specified and taken into account in the model

The concept of surface infrastructure is formed depending on the potential production capabilities of the reservoir and has considerable variability.

The total number of actual and planned wells in the field is more than 1,300, including more than 700 production wells and about 600 injection wells. All wells are ESP lifted.

Considering infrastructure capacity constraints and requirements for optimal pipeline utilization, the use of different numbers of drilling rigs directly affecting the utilization of oil treatment and delivery facilities was evaluated.

29 main variations of the field development strategy until 2060 were formed and calculated, based on the integrated model. The main parameters of variation were the capacity of preparation facilities, the degree of oil separation, the scheme of product transportation, gas utilization capabilities, drilling rigs and subsurface equipment. All scenarios in the integrated model took into account constraints - on target bottomhole, wellhead and line pressures, in order to operate real facilities in accident-free mode.

In the course of calculations, an optimal scenario was selected, which made it possible to increase oil production in 2021 by optimizing the transportation of produced products to the treatment facilities. This scenario formed the basis of the asset development strategy.
Experience of Surfactant-Polymer Flooding Simulation on a Sandstone Reservoir
Authors: Kudryashov Alexey , Karseka Kiryl , Mityurich Denis , Lompik Vasilii , Cheremisin Alexander , Spivakova Margarita
Published: October 2021

The aim of the work is to create representative 1D- and 3D-models of surfactant-polymer flooding, considering the most significant physical and chemical phenomena that occur during this process, and further efficiency evaluation of the method. The paper describes approaches to reproduce and verify laboratory experiments results of recovery factor increase during surfactant-polymer flooding on core samples using 1D-model, as well as approaches to optimize the compositions and injection schemes of chemicals during the efficiency evaluation of the technology on a 3D-model of the pilot site.
A Critical Review of Capacitance-Resistance Models
Authors: Alghamdi Ahmed , Hiba Moaz , Aly Moustafa , Awotunde Abeeb
Published: October 2021

A Capacitance Resistance Model (CRM) is an analytical model that only requires production and injection rates to predict reservoir performance. The CRM input is the injection rates and the output is the production rate. The input and output are related by the CRM parameters. The first parameter is the time delay (also called time constant) and is a function of pore volume, total compressibility, and productivity indices. The second parameter is the connectivity (also called gain, or weight), which quantifies the connectivity between producers and injectors (i.e. how much of the input is supporting the output).

The CRM was developed for fields with minimum reservoir data, or for small fields not requiring a full reservoir simulation model, which can be time-consuming and expensive. The CRM is a quick, powerful analytical tool that is simple to use and requires readily available data. Most of the time, the injection and production rates are measured accurately and frequently, either weekly or bi-weekly. By solving the continuity equation for a homogenous reservoir (i.e. constant reservoir and fluid properties throughout the reservoir) the solution of the continuity equation can be indicative of the injection and production relation and therefore can be used to optimize injection schemes for higher ultimate hydrocarbon recovery. It is important to recognize that the CRM is not supposed to replace numerical reservoir simulators, which, in essence, are the most accurate means of reservoir performance prediction. Instead, the CRM aims to be a quick and easy way to infer reservoir performance in the absence of full-fledged simulation.

The CRM has been used for several purposes as seen in the literature. First, as a tool to optimize waterflooding in oil reservoirs. The CRM can infer inter-well connectivity which will allow the engineer to adjust water injection rates to ensure uniform sweep in the reservoir and reduce the chance of early water breakthrough. The CRM was also used to optimize CO2 sequestration, whereby CO¬2 is captured from the atmosphere and stored in subsurface formations.

The main hypothesis in CRM is that the characteristics of the reservoir can be inferred from analyzing production and injection data only. CRM does not require core data, logs, seismic, or any rock or fluids properties. This hypothesis can be challenged easily since most reservoirs have gradients of fluid properties, multi-porosity systems, and heterogeneous formations with different wettability presences. Albeit, several publications have shown that CRM can result in high certainty output.

The objective of this report is to explain the concept of the CRM, conduct a critical review of the main CRM publications, compare CRM to other reservoir characterization tools and finally demonstrate some applications of the CRM.
Metrology and Standardization in Geomechanical Modeling - A Quantitative Assessment of Uncertainty Window Based on Calibration Data
Authors: Tatur Olga , Petrakov Yuri , Sobolev Alexey
Published: October 2021

Geomechanical modeling is an integral part of the oil and gas industry and is used in all life cycles of the field - monitoring and improving the efficiency of well construction, choosing a completion system, modeling hydraulic fracturing processes, modeling development processes taking into account changes in the stress state of the reservoir, taking into account the fault, salt tectonics, control over the development of the reservoir, control of subsidence of the earth's surface. The success of geomechanical modeling directly depends on the quantity and quality of input data. In contrast to the geological and hydrodynamic models, in geomechanics there is still no unified approach and algorithm for quantifying the model error. The quality of the geomechanical model is defined as "satisfactory" / "not satisfactory" and "confirmed by actual data" / "not confirmed by actual data". In a series of articles on "Metrological support of a geomechanical model", the authors show an algorithm for a quantitative assessment of the error of a geomechanical model. The proposed algorithm takes into account the measurement error (in the well and in the laboratory), the quality of logging data, direct measurements or reconstructed measurements, the tightness of correlations (both for the results of core studies and for the reconstruction of missing logging data), the calculation of the uncertainty taking into account the calibration information.

This paper describes a generalized algorithm for quantifying the error of a geomechanical model, presented in previous articles, and provides a method for quantifying calculate the uncertainty, taking into account calibration information, such as measurements of horizontal stresses, core studies in laboratory conditions.
Recovery of Lithium from Associated Water of Oil and Gas Deposits
Authors: Gavrilov Anton Yurievich , Bandaletova Alexandra Alexandrovna , Devleshova Natalia Alekseevna , Galin Evgeny Vladimirovich , Pisarev Mikhail Olegovich , Liss Dmitry Alexandrovich
Published: October 2021

Current production conditions and development of oil fields are complicated by the development of increasingly difficult-to-recover reserves as well as by the consequences of 2020, which include a change in the structure of demand and a collapse of the oil market, the global trend towards low-carb fuel systems and the implementation of the principles of environmental, social and managerial responsibility (ESG).

This research paper is focused on diversification of the oil and gas business by extracting lithium from reservoir waters of oil and gas condensate fields. This method allows to increase the profitability of deposits. The paper also carries out a technical and economic assessment of the process of the sorption lithium extraction from the formation waters of oil fields.
The Productivity of Horizontal Wells in an In-Line Development System in Fields with Oil Rims
Authors: Samolovov Dmitriy Alekseevich , Varavva Artem Igorevich , Polyakov Vitalij Olegovich , Sandalova Ekaterina Evgenevna
Published: October 2021

The study proposes an analytical method for calculating the productivity of horizontal wells in a line-drive development pattern in fields with oil rims. The paper presents an analysis of existing techniques and compares them with the results of detailed numerical experiments. It also shows the limited applicability of existing techniques. On the basis of the obtained solution of a single-phase flow equation for a line-drive pattern of horizontal wells, an analytical formula was obtained which more accurately describes the productivity of wells beyond the limits of applicability of existing methods. The resulting formula is in good agreement with the results of a detailed numerical experiment.
Prediction of Dynamical Changes Hydrogen Sulfide Concentration During South-West Gissar Gas-Condensate Fields Development
Authors: Descubes Elena , Yessalina Svetlana , Kuvanyshev Amir , Zhelezova Anna , Shaikhina Dana , Chertenkov Mikhail Vasilyevich , Barannikov Andrey Valeryevich
Published: October 2021

An unexpected raise of hydrogen sulfide levels during development of several gas condensate fields in Southwestern Gissar, producing from naturally fractured carbonate reservoirs, observed within a year, lead to necessity of full scale comprehensive investigation. For planning of effective mitigation strategy important questions related to the reasons of hydrogen sulfide level growth and prediction of its further behavior have been addressed in the present study.

The entire investigation process encompassed both theoretical and practical parts. Theoretical part covered evaluation of sour gas sources that was crucial in respect to selection of conceptual methodology for predictions. All possible contributing sources including primary and secondary have been investigated to discern the causes and consequences of hydrogen sulfide occurrence. Practical component of the study employed cut to edge technologies tested and implemented in reservoir simulation.

Based on conceptual constraints with the use of existing field data, interpretation results and regional knowledge basin and 3D static models with fracture network have been developed. Obtained modeling results have been integrated into compositional model, allowing to predict with applied uncertainty analyses further H2S content change during field development.
Study of Reservoir Properties of Turonian Formation Using Digital Core Analysis
Authors: Yakimchuk Ivan , Korobkov Dmitry , Pletneva Vera , Ridzel Olga , Varfolomeev Igor , Reimers Iryna , Safonov Ilia , Evseev Nikolay , Dinariev Oleg , Denisenko Aleksandr , Samokhvalov Andrey , Khan Vladimir , Kusov Anton , Tyurin Evgeny , Korolev Aleksandr , Sitdikov Rustam , Maksimov Evgeny , Loznyuk Oleg
Published: October 2021

The work demonstrates results of reservoir properties evaluation using a complex of laboratory and multiscale digital core or digital rock analysis. Rock properties (including relative phase permeabilities) were studied at different scales: from nanometers to meter (whole core).

For the first time, cores from Turonian formation were characterized with digital rock analysis, which provided stationary relative permeabilities for gas-water under reservoir conditions. Lab determination of relative permeabilities was rather challenging for some low-permeability samples (<0.02 md), while digital analysis was successful even for them. Gas recovery in a depletion mode from different rock types was studied on a whole core model for different capillary pressures. Such studies are not conducted in the lab.
Digital Rock Extension of Laboratory Core Test Results for Acid Treatment Optimization
Authors: Ivanov Evgeny , Korobkov Dmitry , Sidorenkov Alexander , Varfolomeev Igor , Stukan Mikhail
Published: October 2021

Nowadays acidizing became one of the most common approaches used to increase the hydrocarbons production from carbonate reservoirs. An acid solution injected under pressures below the formation fracture pressures dissolves the rock matrix and, thus, facilitates the fluid flow.

However, the overall treatment efficiency is crucially dependent on the acid composition and injection scenario, since the different dissolution patterns are created depending on the effective reaction rate (i.e. acid composition and matrix mineralogy) of the reactive fluid and the fluid injection rate. At slow injection rates, when the acid is spent before penetrating deep into the rock, the face dissolution scenario is observed. On the other hand, fast injection results in uniform distribution of the acid along the treatment zone and similar uniform dissolution of the matrix. The best result from production improvement point of view is achieved when the acid creates a set of thin channels - the so-called wormholes. This optimum regime corresponds to the minimum in the pore volume to breakthrough (PVBT) dependence on injection rate (Fredd, 1998; Zhang, 2021). Where PVBT is defined as the amount of treatment fluid (measured in core pore volumes) required to be injected before the appearance of macroscopic flow channel linking the opposite faces of the core. Thus, since the optimal acid composition and the injection rate are determined by geology and lithology of the reservoir, to achieve the best effect, each treatment should be preceded by experiments on representative rock samples.

In addition to that, the parameters to be optimized for a typical acidizing job also include the sequence of injected fluids and the amount of the fluid to be injected (Yudin A., 2021), which requires an extensive laboratory study. Unfortunately, the amount of the core material available is usually not sufficient for such a comprehensive laboratory analysis. Moreover, the destructive nature of acidizing experiments imposes the fundamental limitation: experiments are performed on different core samples, which makes the results less conclusive.
Application of the Results of Chromatic Technology Data Interpretation in Seismogeological Modeling of Continental Deposits of Western Siberia on the Example of the Zapadno-Ust-Balykskoe Field
Authors: Igitov Semen Mikhailovich , Esipenok Ivan Nikolaevich , Ishkinov Azat Mavlutovich , Vanina Anastasiia Sergeevna , Olkhovsky Konstantin Gennadievich , Romanov Denis Vladimirovich , Lyubimov Sergey Anatolyevich , Goncharova Natalia Alexandrovna , Krikunova Valeriya Sergeevna
Published: October 2021

The aim of the article is creation a conceptual model based on the data of chromatic technology data interpretation to improve the quality of forecasting potentially productive areas of occurrence of Jurassic formations of the Tyumen formation, as well as ranking the deposit by priority zones based on multifactor analysis. The article uses methods of complex reinterpretation of seismic and geological-geophysical materials in order to search for and localize highly productive zones of the Tyumen formation formations. The result of the work is a detailed strategy formed: the exploration and production drilling of the J2 formation. A significant increase in the expected ability of potentially productive objects in the inter-well space in the conditions of complex reservoirs due to modern processing technologies and interpretation was noted. The prospects of translating the methodology for optimizing the development of Jurassic objects of the Tyumen Fm at the fields of Slavneft-Megionneftegaz and other assets of Russian oil producing companies are revealed.
Managing Gas Well Blowouts: Case Studies from Assam-Arakan & Krishna-Godavari Basin
Authors: Bharadwaj Rishabh , Kumari Bhavya , Patel Astha
Published: October 2021

E&P activities are the early stage of energy production and pivotal for generating and sustaining economic growth. However, negligence and evaluating the circumstances incorrectly during these operations can lead to calamities like blowouts. This paper discusses two such tragedies, the Pasarlapudi (Krishna-Godavari) Gas Well Blowout of 1995 & Baghjan (Assam-Arakan) Oil Field Blowout of 2020, and provides possible well control measures and lessons learned.

Pasarlapudi blowout incident occurred during the drilling operations. The pipe stuck-up situation at 2727m MD (Measured Depth) was detected by conducting a stretch test. Further analysis could include circulating brine, checking lost circulation and identifying casing leaks by measuring Sustained Casing Pressure (SCP), Operator-imposed Pressure (OIP), and Thermal-induced Pressure (TIP). Baghjan's gas well at the depth 3870m was producing at 2.8-3.5 MMSCFD. The aim was to plug the lower producing zone and recomplete the well in the upper Lakadong+Therria sand zone. Well was killed using brine, cement plug was placed and BOP installed. BOP was removed after the plug was set to begin the process of moving the workover rig. Well blew gas profusely during this process.

Simulating a blowout and facing one, are two completely different situations. In Pasarlapudi's case, the well blew with an enormous gas pressure of 281.2 ± 0.5 kg/cm2. While drilling the production hole (8.5 inch), either differential pressure sticking, presence of water-swelling clay formation or the partial collapse of wellbore formation caused the pipe stuck-up situation. By conducting stretch test along with circulating brine, root cause of this problem could be identified. If differential sticking occurred, lost circulation could be checked & cured, while keeping the hole full. Circulating brine should solve the problem of swelling clay formation while formation collapse could have occurred due to the presence of plastic formation like salt domes.

In the case of Baghjan gas well blowout during workover operations, probable safety measures could include placement of 2 or 3 backup cement plugs along with kill fluid or going for squeeze cementing before placing the cement plug & kill fluid while abandoning the lower producing zone. Attempts were made to bring the well under control by adequate water spraying, installing BOP. Water was pumped through the casing valve and a water reservoir was dug near the well plinth for the placement of pumps of 2500 gallon capacity.

Proper safety measures should be used even when they're not the cheapest to avoid repetition of treatments and detrimental situations. SCP, OIP and TIP should be measured periodically whenever possible and the root cause of situations like lost circulation, pipe stuck-ups, kicks, casing leaks should be identified before proceeding towards drastic remedial operations. Innovations in countering well-control situations should be promoted invariably.
Technology for Monitoring Gas and Water Breakthrough Intervals using Chromate Desorption Systems in the Development of Fields in the Caspian Sea
Authors: Shtun Sergey , Senkov Alexsandr , Abramenko Oleg , Nikishin Igor , Efimov Evgeny , Minakhmetov Radik , Platonov Igor , Nukhaev Marat , Kabanov Vasilii
Published: October 2021

The paper presents a novel technology for determining the intervals of gas and water breakthrough in the development of fields on the Russian shelf of the Caspian Sea. The proposed technology is similar to traditional production logging and monitoring of horizontal wells using fiber optic systems.

The technology aimed at determining the phase components is based on chromate desorption systems (CDS) with individual selective analytes used. CDS are installed on the lower well completion equipment (sand filters, inflow control devices, multistage hydraulic fracturing equipment and so on) and have a unique combination of pairs of oil-, water- and gas-soluble analytes for each interval. From the CDS, an analyte begins to release when in contact with a target fluid to surface with this fluid. At the wellhead, samples are taken according to a specific program, then laboratory analysis by chromatographic methods and mathematical interpretation of the composition of the inflow are performed. The paper presents an example of work when the intervals of gas outs were determined directly in the field using a micro-chromatograph.
Workflow of Petrophysical Analysis Performed at Mine in Karaganda Coal Basin
Authors: Bektybayeva Makpal , Mendybaev Nurhat , Bigeldiyev Asfandiyar , Basu Subhro , Abetov Auez , Temirkhassov Aidos , Tyulebayeva Ranida , Yermukhanbet Aiyazhan
Published: October 2021

For accurate coal bed methane (CBM) reserves estimation, it is necessary to evaluate reservoir characteristics. We present a workflow for formation evaluation of coalbed-methane wells, by interpretation of a limited number of legacy logs, including data preprocessing, lithology identification, proximate analysis and estimation of gas content of coal beds.

This workflow allowed the estimation of ash content from the available logs, including selective log (analogue of photoelectric absorption), which was recorded only on the territory of the former Soviet Union and never used for such calculations before. Even though the logs were recorded by old tools with low vertical resolution, we were able to identify heterogeneity of coal seams, using the principle of core ash content distribution. Integrated analysis of old core data and recent laboratory measurements of samples from coal pillars allowed to calculate proximate properties of the coal, which showed good match with observed data and could be considered as input parameters for property distribution in the geological model.

Also, it is worth to mention that an advanced plug-in was deployed to perform calculation of proximate properties and gas content for all available options and to significantly reduce time for screening different algorithms and rapidly analyzing results.