bluuebunny/crossref_metadata_2025_split huggingface dataset:
Streaming Machine Learning for an Oilfield Development System Selection Based on a Complex Optimality Criterion
Authors: Sun Daria Vitalievna , Okunev Maksim Vadimovich 
Published: September 2020

Abstract
In this paper we present the methodology to predict the value of the complex optimality criteria from the parameters of the oil field development system such as well spacing, the distortion factor, the type of well completion, the horizontal length of the end of switching time, etc. The method presented in this paper is based on the results of multivariate calculations in a hydrodynamic simulator and the use of correlation models of machine learning (ML).
New Technology for Inverse Problem Solving of Digital Core Model Construction Using Stochastic Modeling and Particle Swarm Optimization
Authors: Markov Pavel 
Published: September 2020

Abstract
The goal of this article is to present a new technology of inverse problem solving for constructions from scratch or parameter clarifications of pore-scale models and parameters of simulated multiphase flow processes, particularly associated with EOR methods. The solution of these problems is relevant because of the increasing use of digital core analysis and pore-scale modeling and the presence of problems associated with determining of missing model and flow processes parameters hindering the further development of these methods.
The technology for solving inverse problems for digital core models contains: the developed method for stochastic generations of pore network models, the simulation method for one- and two-phase flow, the suggested objective functional, and the particle swarm optimization method. The developed model construction method is based on the stochastic generations of all parameters for pores and capillaries according to their distributions: radii and shape factors of pores and capillaries, pore coordination numbers, capillary lengths. The suggested objective functional estimates deviations of calculated parameters from known reservoir parameters for core samples: porosity, permeability, capillary pressure, relative permeability.
The technology solved the following problems, what have been shown on the basis of three practical cases: assessments of local distributions of parameters (e.g., contact angles) what is difficult to estimate experimentally; submicron pore reconstructions which are "not visible" using μCT; model constructions corresponding to the experimental reservoir parameters; models (millimeters) rescaling to sample sizes used for flow experiments (centimeters); digital core model estimations which are typical on reservoir scales for parameter calculations, e.g., for reservoir simulation models.
The developed technology for digital core model constructions based on stochastic modeling was first used for three oil and gas fields. The technology allows to solve a part of problems that hinders wider applications of digital core analysis and pore-scale modeling, particularly in EOR efficiency estimations. One of the problems is the transfer of results of the millimeter sample scale to the centimeter sample scale and, further, to scales of reservoirs where the solution is to build stochastic models.
Geosteering Based on Integration of LWD and Surface Logging Using Machine Learning
Authors: Galkina Alena Vladimirovna , Yalaev Tagir Rustamovich , Lisitsyna Marina Yurievna , Rakhimov Timur Rinatovich 
Published: September 2020

Abstract
This study presents an approach based on machine learning to predict the lithology at the bit while drilling. This is necessary for (near) real-time adjustments of well path while providing reservoir characterization (reservoir rock, non-reservoir rock and tight rocks). The approach is based on an ensemble of decision trees and gradient boosting. Work on this project included analysis and preprocessing of the data, selection of features for training, creation of additional features to improve the quality of the model, comparison of machine learning algorithms to identify the most effective within the task, optimization of the hyperparameters. After that, the final model is built on a training dataset with desired outputs obtained from LWD formation evaluation and the quality of the algorithm is evaluated on a test dataset with the selected metrics.
The computer program developed on the proposed approach receives drilling data as input and provides a reservoir characterization. High quality of the model is necessary for successful geosteering of horizontal wells due to the rapid detection of lithology changes in the reservoir and increasing the efficiency of well drilling by minimizing penetration through the non-reservoir rocks, which can further increase oil production. The proposed approach provides an accuracy of 80-90% for a number of oil fields.
Building a Unified Compositional Model
Authors: Bogachev Kirill , Zhukov Sergey , Milyutin Sergey 
Published: September 2020

Abstract
The construction of unified compositional model is important for modeling of production surface network. The produced streams are described by different multicomponent PVT models, while total production calculation requires a single consistent PVT system. The method for constructing a compositional model which is optimal in terms of components number is proposed.
As a first step, all components from all initial mixtures are split by molecular weight into two groups: light and heavy, which are considered separately from that point on. The basis component set for the light group is constructed from the pure hydrocarbons and inorganic substances. Then the components from the light group are expanded over it using the method of numerical minimization. The objective function used is the sum of the moduli of the relative differences of corresponding parameters of initial components and their decompositions. The parameters considered are critical properties (pressure, temperature, volume) and the acentric factor. The condition of equality of molecular weights is enforced, to ensure the conservation of material balance during decomposition of the initial components. Two methods are proposed for the characterization of heavy components: either proceed the same way as it is done for the light group, with the construction of a corresponding basis, or use fractionation by the number of carbon atoms. All properties of the components of the final set are fully known after the above algorithm has been applied. Each component in the initial mixtures is decomposed using the resulting set of components with uniquely defined coefficients.
The proposed method is successfully used to construct a unified compositional model for production surface networks. The sources (pipelines or wells) with different PVT models are connected in the single production network computed by resulting compositional PVT properties.
Coupled Static and Dynamic High Resolution Modelling on High Performance Computer Clusters
Authors: Absalyamov Artem Vadimovich , Bogachev Kirill Yurievich , Glazkova Ekaterina Alekseevna , Kostin Georgii Aleksandrovich , Telishev Alexey Sergeevich , Tregub Semen Leonidovich , Shimonin Egor Yurievich 
Published: September 2020

Abstract
Significant acceleration of the calculations used to create three-dimensional geological and hydrodynamic models is discussed. Detailed 3D models of large and giant reservoirs requires significant computing power for their creation. All available seismic, geological and hydrodynamic data on the oil and gas field, which must be taken into account in a detailed model, require the construction of a grid from several hundred million to several billion blocks. A method proposed for integrated static and dynamic model calculation allows the most efficient usage of a parallel computing cluster system capabilities.
Development of Acidizing Simulator for Sandstone Reservoirs
Authors: Blonsky Artem Vadimovich , Mitrushkin Dmitrii Aleksandrovich , Kazakov Artem Vyacheslavovich , Filippov Danil Denisovich , Mokropulo Yury Ivanovich , Bazanov Ilya Evgenevich , Shcherbakov Georgii Yurievich , Melnikov Alexander Viktorovich , Roshchektaev Aleksei Petrovich , Maltcev Andrei Andreevich , Morozov Maxim Aleksandrovich 
Published: September 2020

Abstract
In this paper it is described the approach of constructing the design of acid treatment and the tools of the software designed to solve this problem. The developed simulator includes a hierarchy of calculation modules that differ in the degree of detail of the physical effects. In addition, a number of engineering modules was developed as a part of the simulator: well data preprocessing module, history-matching module, optimization module.
The mathematical models in the simulator take into account the multicomponent composition of the liquid, an arbitrary number of minerals in the solid phase, and an arbitrary number of kinetically controlled heterogeneous and homogeneous chemical reactions. Moreover, the models take into account the non-Newtonian rheology of diverters and the thermal effects during chemical reactions. The geometry of the well and hydraulic fractures can be explicitly resolved on 3D Voronoi grid in the framework of developed approach.
The developed algorithms were tested by real data. It is demonstrated that precipitation resulting from secondary and tertiary reactions can have a determining effect on the result of acid treatment. The article presents the results of simulation acid treatment in a vertical well with a colmated hydraulic fracture. It is shown that acid treatment led to complete restoration of the fracture conductivity. The results of the two acid treatments analysis are also presented. When analyzing the first work it was possible to determine the reasons for the unsuccessful treatment by the adaptation model to the production data and to select an acid composition that provided maximum efficiency.
When analyzing the second treatment for the well, an analog was found on which acid treatment was performed. The model parameters were adapted to the results of acidizing for the analog, and the parameters obtained as a result of the adaptation were used to simulate treatment at the original well, which led to the agreement of the simulation results with the real data. Then, it was shown under the result of design optimization that more intensive acid treatment should have been performed on the original well.
Assessment of Non-Equilibrium Phase Behavior Model Parameters for Oil and Gas-Condensate Systems by Laboratory and Field Studies
Authors: Indrupskiy Ilya Mikhailovich , Danko Mikhail Yurievich , Tsagan-Mandzhiev Timur Nikolaevich , Aglyamova Ayguzel Ilshatovna 
Published: September 2020

Abstract
Non-equilibrium phase behavior of hydrocarbons has a great influence on the development of gas condensate and oil and gas condensate deposits, as well as oil deposits after evolution of dissolved gas. The key parameter of mathematical models that take into account non-equilibrium phase behavior is the characteristic relaxation time. The paper presents examples of assessing its value according to the results of laboratory experiments and well tests, which also allow verifying the mathematical model and obtaining input data for the production forecast taking into account non-equilibrium processes.
A model of non-equilibrium phase behavior in a compositional formulation, based on relaxation of the chemical potentials difference, was verified on the data of a laboratory experiment in a calorimeter cell. The numerical algorithm for calculating the dynamics of phase fractions and compositions in a non-equilibrium process was modified to take into account the isochoric condition, which made it possible to directly compare the simulation results to the real experiment. A good match of the experimental pressure-temperature hysteresis curves was obtained without additional adjustment of the characteristic relaxation time as compared with the estimate obtained from processing the measured pressure relaxation curve. Thus, the adequacy of the mathematical model and the possibility of evaluating its parameters directly from the experimental measurements were confirmed.
An example of assessing the characteristic relaxation time from well test data is presented for the pressure buildup (PBU) curve recorded under the conditions of gas dissolution in oil. A sector blackoil-type model was used for the well drainage area. For matching the PBU data, various modeling methods for non-instant gas dissolution were considered, including a model based on relaxation of solution gas-oil ratio (sGOR). The results of simulations with the sector model showed that the traditional options for limiting the sGOR increasing rate do not allow adequate matching of the PBU curve under conditions of gas dissolution. For the model that takes into account the sGOR relaxation, an in-situ estimate of the characteristic relaxation time was obtained which provided a fine match of the PBU data. As expected from theoretical concepts, the characteristic relaxation time for the in-situ process has a much larger order of magnitude than for the laboratory experiments on centimeter-sized cells.
The results of the study show the adequacy of relaxation models for non-equilibrium phase behavior in compositional and black-oil formulations for describing real processes and demonstrate the possibility to estimate the characteristic relaxation time from laboratory experiments and well tests, taking into account its dependence on the process scale.
Assisted Creation and Usage of Material Balance Models for Production Forecasting as a Part of Integrated Field Management
Authors: Bakhty Nikolay , Demin Albert , Tupitsin Maksim 
Published: September 2020

Abstract
For decades, computer simulation has been an inevitable part of hydrocarbon reservoir development. 3D reservoir models of productive reservoirs and gathering system pipeline models exist for almost all operated fields.
The recent concept of digital oilfield relies much upon performing computer simulation in order to automate the development process. Operational field development management is one of the processes that can be automated within this concept. However, conventional computer simulation techniques based on the above-mentioned 3D reservoir models are ill-suited for automation of operational development management. This can be attributed to the fact that creating, history matching, updating, and calculations of such integrated models are very time-consuming.
Integrated models based on simplified models of productive reservoirs can be regarded as a basic means of operational field management. A case in point are models built on material balance equations. However, this approach has its drawbacks. The main problem lies in having to do double the work. One has to have two models for each productive reservoir: one model for operational development management (simplified model) and the other for conventional modeling (3D reservoir model). This paper considers solving the stated problem by transforming a conventional 3D reservoir model of a productive reservoir into a material balance model and provides comparative analysis of both modeling approaches.
West Siberia Jurassic Sediments Rock Typing and Digital Models Creating for Geological Model Refining
Authors: Blotskaya Arina Igorevna , Sardarov German Serderovich 
Published: September 2020

Abstract
The developed transition saturation zone and the presence of free water above the accepted level of OWC, which is usually characterized by undersaturated reservoirs, greatly complicates the development of deposits and requires updating the geological model based not only on the standard partition of the lithotype section according to well log data, but also involving the results of core material research.
The aim of this work is to interpret well logging data using rock typing in the conditions of a developed transitional saturation zone and the presence of free water above the accepted OWC level. The work was carried out in one of the Western Siberia oil fields in the Upper-Middle Jurassic terrigenous sediments. The work is based on a comparison of interpretation algorithms based on a standard approach and on the basis of building flexible interpretation algorithms and creating an interactive system of petrophysical modeling. In addition, intermediate conclusions will be shown, such as the use of a calibrated fluid model based on special core studies data for standard log data for drilling horizontal and pilot shafts. Comparison of the core data results interpretation and the petrophysical model constructed by the volumetric method.
Reservoir Flow Connectivity Estimation and Its Using in Geomodeling: Tomsk Area Case Study
Authors: Popov Victor Lvovich , Zakrevskiy Konstantin Evgenyevich , Podnebesnykh Alexander Vladimirovich , Krasnoshchekova Lubov Afanasyevna 
Published: September 2020

Abstract
The method for quantitative prediction of the reservoir connectivity is given for one of the oilfields of Tomsk area. The studied upper Jurassic reservoir was formed in coastal environment and penetrated with a small number of wells.
The volume of recoverable oil is depend on chosen method for lithology or N/G modelling. The calculations, which were done on geology and simulation models, showed that recoveryg factor changes can reach 35% and related to reservoir connectivity. The Tomsk area reservoirs geomodels, which have production history and total oil production, is higher than 60% of recoverable oil reserves, were studied in order to develop method to predict connectivity coefficient of reservoirs. The relations between reservoir heterogeneity and sedimentology features and log data were found. It allowed making prediction for connectivity coefficient value for case study reservoir.
In addition, production data of two wells of case study reservoir were considered. Analysis of wells from other Tomsk reservoirs with the same completion type shows that connectivity value is related with well production rate drop factor. This regression allows predicting desired connectivity coefficient for case study reservoir in order to provide appropriate heterogeneity to match model with production history data.
Finally, the modeling method with continuous N/G property was chosen for geomodel. This is the only method, which allows achieving heterogeneity level that corresponds to sedimentary environments, log features and production history data. As a result, more accurate geomodel was created which has lower uncertainty lever in prediction of reservoir properties in non-drilled part of the reservoir.
Completion Strategy Alteration on an Overpressured Field Based on Geomechanical Modeling and a Geomechanics Based Fracture Design
Authors: Korelskiy Evgeny Pavlovich , Ochirov Gleb Olegovich , Kosareva Marina Sergeevna , Chernyak Vyacheslav Sergeevich , Peshkov Igor Viktorinovich , Kosarev Taras Igorevich , Sadykov Lenar Alfatovich 
Published: September 2020

Abstract
Hydraulic fracturing as an approach of oil and gas recovery intensification in clastic formations has long been well known and recognized from technological and economical sides. However, in spite of the obvious advantages of hydraulic fracturing procedure, the method has its drawbacks which decrease the final oil and gas productions.
One of these disadvantages is a fracture breakthrough into the adjacent layers with following water cut increase and reduction of cumulative oil and gas production and production rates. Bearing in mind the geological structure of the explorational targets in this paper, the problem becomes more relevant. The presence of an abnormally high formation pressure in the reservoir, which exceeds the surrounding shale's pressure, and the shale barrier, which does not provide a sufficient stress barrier, promotes possible breaks of fractures into the overlying water-bearing zone.
Owing to the simulation of hydraulic fractures based on the geomechanical model, it was possible to implement the hydraulic fracturing strategy and planning, taking into account the understanding of the geomechanical parameters and the stress-strain state of the medium, in which it was possible to avoid breakthroughs of hydraulic fractures into the overlying water-saturated formation. In addition, it is shown that outwardly similar development objects may require radically different approaches to well completion.
Improved Well Construction Enabled by Pore Pressure Prediction While Drilling in Zapadno-Yurkharovskoe Field
Authors: Chettykbayeva Kamilla Nusupbekovna , Grigoriev Maxim Sergeyevich , Shakunov Alexander Anatolievich , Korotkov Stanislav Aleksandrovich , Kovalevskiy Andrey Valer'evich , Bybin Pyotr Valer'evich , Nikitin Ivan Andreevich , Zinovyev Alexey Alexeevich 
Published: September 2020

Abstract
Jurassic deposits of Zapadno-Yurkharovskoe oilfield include laminated sequences of sandstones and shales and characterized by overpressure (up to 830 atm at 4000m depth). The challenging clinoform geology of Achimov layers above the target formation presets the environment where pore pressure can differ significantly even in one statigraphic unit at the same depth. It is of paramount importance to determine the setting depths of production casing and that of the first liner of horizontal wells with respect to quantitative description of pore pressure increase with depth. According to the drilling history in the area, overdeepening the production section can lead to gas kick and the need of weighting up the mud, which can result in extreme losses while cementing the casing; stopping the drilling early can increase the risk of incompatible conditions in the first liner section.
The objective of this study was to assess the pore pressure in real time to determine the best depth of setting the casing in the conditions of high uncertainty, since the field is not yet explored thoroughly neither by 3D seismic nor by drilling.
The drilling analysis and geomechanical modeling revealed that the safe mud window of horizontal wells is extremely narrow: the drilling limits between pore pressure-collapse gradient and mud losses gradient in some intervals do not exceed 0.08-0.10 specific gravity. The established criteria for setting the production casing depth is to stop the drilling when the pore pressure reaches 1.35 g/cc of mud weight equivalent, the next section is to case the shale sequence with the increase of pore pressure from 1.35 to 2.10-2.12 g/cc of mud equivalent, lastly, the production liner cases the gas condensate bearing reservoirs drilled with the heaviest muds of up to 2.15-2.18 g/cc to offset the pore pressure and stabilize the overlying Abalak deposits, which are prone to breakout.
The best drilling decisions are to made in the conditions of extremely complex geology, uneven pore pressure distribution and in the absence of seismic inversion results. The established criteria for well design and the techniques of pore pressure assessment have already proved positive for the well #5. These experience and methodologies can be interesting and useful for other projects managing the overpressured low permeability reservoirs in Western Siberia as well.