bluuebunny/crossref_metadata_2025_split huggingface dataset:
Efficiency Application of a Reactive Multi-Component System for Mud Loss Control in the Timano-Pechora Region
Authors: Nechaikin Anton , Morozova Anastasia , Sekacheva Yulia , Musabirov Ildar 
Published: September 2020

Abstract
In the Timano-Pechora Region, the drilling of the 178 mm hole for the production casing in horizontal wells is often accompanied by challenges attributed to mud losses in thief zones. These challenges may not be overcome by application of conventional lost circulation materials (LCMs), often resulting in the abandonment of the parent wellbore and re-drilling of the section. A reactive multi-component system was proposed to the operator as an alternative solution to control mud losses while drilling this section and assist in reducing the well construction costs and duration.
The multi-component reactive system has been developed as a combination with an oil-based fluid used to support reactions with water-based fluids in the well, regardless of the mud chemistry. When the oil-based composition contacts water-based fluids, it forms a coagulated, moldable substance that plugs off the mud loss channels in the near-wellbore zone. The substance does not ingress further into the matrix or fractures and, therefore, it does not provide any negative impact on the permeable zone of the reservoir.
Prior to implementing the multi-component reactive system, the drilling of the 220.7 mm section used to be accompanied by mud losses as high as 100 m3/h. Two pilot operations utilizing this system demonstrated reduction of mud losses by 100%, thus allowing timely drilling of the 220.7 mm sections within the schedule. Furthermore, the 178 mm casing strings were run to TD with successful cementing, and without the need to sidetrack. The estimated time savings from application of the multi-component reactive system was 20% in comparison with the previously drilled four wells.
The new technology helped the operator achieve success in preventing mud losses during well drilling, and removed the need for wellbore re-drilling. As the system may be pumped directly through the BHA, this provides additional time savings in not having to trip out of the hole. Based on the results of the pilot operations, this technology has demonstrated its advantages for solving lost circulation issues while drilling in target intervals. This paper addresses the application of the multi-component reactive system to resolve the lost circulation problem.
Case of Physical Fields Application to Accelerate Oil Preprocessing
Authors: Dengaev Alexey Viktorovich , Verbitsky Vladimir Sergeevich , Getalov Andrey Alexandrovich , Sargin Boris Viktorovich , Grekhov Ivan Viktorovich , Bogdanov Alexander Vladimirovich , Tarasevich Sergei Alekseevich 
Published: September 2020

Summary
The separation of water-oil emulsions in the fields is considered to be a significant part of the costs associated with the production and transportation of the produced fluid. This is mainly connected to the use of chemical reagents (demulsifiers), which accelerate the process of the emulsion separation. The paper proposes a technological solution regarding the method of microdosing of demulsifier, which allows to reduce the concentration of the reagent input and, most importantly, to reduce the volume of the intermediate layer within the process of field oil processing. The proposed device is based on the use of ultrasonic vibrations.
In the laboratory, and later in the field conditions, the tests had been conducted to determine separation efficiency depending on the type of emulsions, oil viscosity, temperature, emitter power and the availability of a demulsifier, etc.
The obtained results make it some possible to reduce the volume of used demulsifiers, as well as increase the efficiency of oil processing.
Metal-Polymer Coiled Tubing
Authors: Grogulenko Vladimir Viktor 
Published: September 2020

Abstract
Metal-polymer coiled tubing (MCT) are flexible pipes based on a copolymer reinforced with steel tape, wires and ropes. During the research was proposed and justified eleven constructions of MCT with twenty options of overall dimensions. Next, mathematical modeling of the actual stress conditions of MCT in standard operations during the overhaul of wells was carried out, as well as calculations of the strength of the MCT. The result was the identification of most promising options for the implementation of MCT, as well as the proposed area of their implementation. In addition, have been introduced coefficients for rational selection of most effective MCT structure for a specific well operation from both a technical and economic point of view. The scientific and technical novelty of metal-polymer coiled tubing is confirmed by Patent for an invention, as well as the results of a thorough analysis of patenting of coiled tubing devices. Application of MCT fully meets the challenges of the modern fuel and energy complex of the Russian Federation in the direction of creating modern and safe technologies for offshore fields (including Arctic fields), as well as within the framework of the import substitution policy implemented in our country. Production of proposed metal-polymer coiled tubing can be organized in a full cycle at domestic enterprises, as well as all components of MCT are also produced in our country. This statement was confirmed when creating prototypes of pipes in a volume of 3000 meters. If ongoing laboratory tests of metal-polymer coiled tubing will be finished with positive results, then will be carried out pilot implementation of the proposed pipes in one of the domestic oilfield services companies. The timing of implementation this idea will be minimal, since significant costs are not required for the re-equipment of factory facilities for the manufacture of the proposed MCT. At the same time, final cost of manufacturing MCT on average, according to research results, is on 50 – 100 percent lower than the cost of a GT-70 steel coiled tubing manufactured by Global Tubing USA of similar dimensions. It is worth noting that the MCT, as well as the steel coiled tubing pipe, fully meets all environmental safety requirements, and that is why its use on offshore projects (where environmental friendliness is one of the main requirements for implemented technologies) is considered the most probable. As for increasing labor productivity, initially coiled tubing is an advanced industry with a high technological level. Application of metal-polymer coiled tubing as an alternative to steel coiled tubing in certain well operations will increase the number of hoisting operations for one pipe, which will increase its service life, and will also help to optimize financial costs of relocating equipment.
Mixed-Integer Programming for Optimizing Well Positions
Authors: Kuvichko Alexander , Ermolaev Alexander 
Published: September 2020

Abstract
The objective of this study is to design advanced methods of integer programming to optimize well positioning on oil and gas fields. In this paper we present a significant modification of new iterative method of solving Boolean and integer programming problems. This algorithm solves not just a static well position optimization, but a dynamic (in time) optimization of newly drilling well positions. These algorithms are suitable for non-regular well location problems when no strong pattern was defined. We have modified and improved an existing technology to optimize producers’ non-regular positions. Instead of running an exhausted search for all possible cases and defining the objective function value for each case (with or without the use of a hydrodynamic simulator), we designed a special iterative procedure. By increasing the number of cases and involving high-performance computing, we can estimate the global optimal point. Special types of Boolean constraints help to take into account existing wells or free of wells zones. Thus, we can solve optimization problems in time, taking into account recently placed wells.
We implemented designed algorithms on models with properties similar to real oilfields, where the number of wells per each problem is from ones to tens, like models of well pads or platforms. We compare different distance criteria based on some common engineering approaches. Optimal solutions of formulated problems are good as initial points for other iterative, gradient-based algorithms of well location problems. We present results of implementations for several cases and describe their optimality. Cases that we present include not just static optimal well positions, but a solution of dynamic problems. We first select a small number of wells to be placed and run the procedure. After drilling and putting into operation of first wells, we solve the optimization problem for further producers to be drilled. We discuss cases when it is rational to use this procedure instead of using a regular well pattern.
Optimization of Carbonate Heavy Oil Reservoir Development Using Surfactant Flooding: from Laboratory Screening to Pilot Test
Authors: Varfolomeev Mikhail Alexeevich , Ziniukov Rustam Anverovich , Yuan Chengdong , Khairtdinov Ruslan Kamilevich , Sitnov Sergey Andreevich , Sudakov Vladislav Anatolevich , Zhdanov Maxim Vladimirovich , Mustafin Aidar Zamilevich , Usmanov Sergey Anatolevich , Sattarov Aidar Ildarovich , Glukhov Mikhail Sergeevich 
Published: September 2020

Abstract
Bashkirian reservoir is a heavy oil fractured carbonate reservoir. It has a low temperature (23 ℃) and an ultra-high salinity (217.5 g/L). The low injectivity is the main problem that limits the efficient development of this reservoir. Hot water injection has been tried to solve this problem, but it did not work. The purpose of this work is to find an effective surfactant system for high salinity condition to increase the injectivity during water flooding. This paper presents the whole process from laboratory screening and numerical simulation to pilot test. In laboratory, ten surfactants were evaluated by measuring interfacial tension (IFT) and wettability change. For each surfactant, three concentrations were studied to obtain the optimal surfactant formulation. The optimal surfactants were used for filtration experiments to evaluate the effect of surfactant on the injectivity and oil displacement efficiency. The effect of the best surfactant was assessed by reservoir numerical simulation at the field scale. Eventually, the pilot test was implemented to test the effectiveness of surfactant injection. According to the ability to reduce IFT and change the wettability, oil displacement efficiency, the capacity of reducing injectivity, and production performance, as well as considering the cost and accessibility of surfactant, one nonionic surfactant was eventually chosen for pilot test in the oilfield.
The pilot test results show that this nonionic surfactant shows a very good effect on improving water injectivity. After the injection of surfactant, the wellhead pressure and downhole pressure were reduced from 40 at and 171.5 at to 24 at and 153.4 at), respectively. Surfactant injection increased additional oil production of about 1094 tones. The good effect of this nonionic surfactant showed in pilot test makes it a good candidate for wide application under high salinity condition to improve well injectivity as well as oil displacement efficiency in the case of complex heavy oil carbonate deposits.
In-Situ Channelization Model for Hydraulic Fracturing Simulation
Authors: Ivanov Maxim Grigorievich , Kaprielova Ksenia Mikhailovna , Starkov Ilya Andreevich , Romanovskii Rostislav Vladimirovich , Bannikov Denis Viktorovich , Kuznetsov Dmitry Sergeevich 
Published: September 2020

Abstract
In-Situ Channelization (ISC) phenomenon comprises a segregation of proppant and fiber-laden slurry in a hydraulic fracture during fracture closure. The segregation can lead to the creation of highly conductive open channels in the proppant pack and can significantly alter the fracture conductivity. Simulating ISC in a fracturing simulator can help maximize channeled areas, thus suggesting a higher production. The nature of ISC represents the slurry bridging at static conditions due to wall roughness and heterogeneities in proppant and fiber distribution. We demonstrate the development of the static bridging model, which we refer to as anchoring. The model is based on the physical principles, namely the force balance. The parameters governing the phenomenon include slurry composition, temperature, fracture walls surface roughness and orientation. Pixel-type approach to laboratory testing is introduced, which aids in the simplification of the model description and the implementation. Fracture waviness and roughness were found to affect the channelization, with fracture inclination angle being the most contributing factor. The model was extended to high temperatures, allowing simulations in the whole working ranges. Verification and validation showed fairly good reproduction of experimental data with the model, with tolerance of the anchoring event determination being within 5 ppt of fiber concentration. Simulations of hydraulic fracturing in the fracturing simulator with ISC model enabled revealed that ISC phenomenon has significant effect in treatments with low viscous fluids (e.g., linear gel or slick water). Meanwhile the effect diminishes as the reservoir temperature increases.
Utilizing Machine Learning Methods to Estimate Flowing Bottom-Hole Pressure in Unconventional Gas Condensate Tight Sand Fractured Wells in Saudi Arabia
Authors: Al Shehri Fahad Hassan , Gryzlov Anton , Al Tayyar Tayyar , Arsalan Muhammad 
Published: September 2020

Abstract
Installation of production tubulars is a critical job that has a direct impact on the overall productivity of the well. Thus, it is equally significant to predict the accurate flowing bottom-hole pressure (FBHP) in order to garner utmost benefits from the system by constructing the right vertical lift performance (VLP) curves. In fact, constructing the accurate VLP curves helps us identify the liquid loading times of wells and hence be able to predict when to install velocity strings or different artificial lift systems. For years, efforts have been made into developing mechanistic models and correlations to predict FBHP. However, all present correlations are developed under laboratory conditions and each have their own limitations for specific types of flow regimes. Mechanistic models integrate the physics of downhole conditions and yet they do not provide accurate results for FBHP. Therefore, artificial neural network (ANN), functional networks (FNN), and long-short term memory (LSTM) models were utilized in this paper. The designed models have been validated over a diverse range of data sets. More than 30,000 data points were collected from various wells with wide range of inputs. The inputs utilized in the AI models are from daily flowback data including wellhead pressure, wellhead temperature, true vertical depth, fluid specific gravity, chloride content, watercut, fluid rates, and water gas ratio. The data were then split as per the ratio of 4:1 for training and testing in order to generate accurate results. Then, the models were tested on other new well to test their accuracy. ANN model has proven to be the most accurate machine learning model and therefore, the results from the designed model were compared with the results of existing empirical correlations and it was evident that AI model outperformed them in terms of average absolute percent error (AAPE), and correlation coefficient (CC).
Digital Rheology of High Viscosity Friction Reducers
Authors: Inozemtseva Elizaveta Andreevna , Kaprielova Ksenia Mikhailovna , Ivanov Maxim Grigorievich 
Published: September 2020

Abstract
High-viscosity friction reducer (HVFR) fluid systems are increasingly used in hydraulic fracturing operations to achieve economic and technical objectives. As with other fracturing fluids, HVFR system performance is tied to rheological properties, which, on their own, are strongly dependent on water salinity.
A novel approach applies digital technology to HVFR rheology modeling for fluid performance prediction in a wide range of water compositions. The proposed model is an effort to digitize and model rheology for increased operational efficiency. It has several remarkable differentiations, including model sensitivity to polymer loading, temperature, and water salinity.
Applying Machine Learning Methods to Exploit Unprofitable Reserves
Authors: Vanina Anastasiia Sergeevna , Palivoda Vasilii Romanovich , Khanipov Ilmir Failovich 
Published: September 2020

Abstract
The prevailing economic situation warrants oil production emerging realities. Increased producibility and efficiency are promising ways of oil industry developing for now. That's why the advanced use of digital technology in the oil industry is one of the priorities today. Digital technology adoption helps to reduce costs by improving existing workflows, and also provides the capability over the longer term to achieve high levels of economic efficiency in the hard-to-recover reserves development.
The study presents key principles for geological and technical measures (GTM) efficiency improving based on machine learning using an accumulated data of previous work statistical data. The study also demonstrates a method based on the results obtained that allows modifying the existing methodology for developing reserves and involving reserves that are unprofitable today.
The use of machine learning has been examined from a different approaches point of view, such as linear regression and decision tree. The convergence of actual and predicted data was more than 80%, based on a test sample.
The proposed methods and workflows are only the first steps in the technology development to improve the next-generation GTM efficiency. Automatic recruiting helps to improve workflows and optimize productivity. That's why the company doesn't go beyond its initial costs, and can also use reserves that are unprofitable today by changing the investment projects setup methodology.
Reservoir Simulation of Polymer Flooding: Challenges and Current Results
Authors: Sabirov Denis Galievich , Demenev Roman Aleksandrovich , Isakov Kirill Dmitrievich , Ilyasov Ilnur Rustamovich , Orlov Alexander Gennadievich , Glushchenko Nikolay Aleksandrovich 
Published: September 2020

Abstract
Most of the Russian oil fields consist of the complex reservoirs and it is required to apply secondary reservoir development methods, such as waterflooding, in order to increase reservoir development efficiency. However, for highly heterogeneous reservoir with viscous oil, "classical" waterflooding is not enough and there is a need to use enhanced oil recovery methods, one of which is polymer flooding. The prospects polymer solutions injection have been proved in different fields worldwide, including the East-Messoyakhskoye field at the PK1-3 reservoir with high-viscosity oil. At this field, polymer flooding pilots were carried out and taking into account the obtained field data, the geological and dynamic model were updated, which helped to improve the process physics understanding and evaluate the possibility of sweep efficiency increase during project implementation.
This paper describes the challenges, difficulties, applied approaches, results and experience obtained in reservoir simulation of polymer flooding.
Thermo-Tectonic Evolution and Numerical Petroleum System Modeling of One of the Oil Fields on Krasnoleninsky Arch, SW West Siberian Basin
Authors: Röth Joschka , Karpov Yury Alexeevich , Kalmykov Anton Georgievich , Beseleva Ekaterina Viktorovna , Littke Ralf , Kalmykov Georgy Alexandrovich 
Published: September 2020

Abstract
In the West Siberian Basin, thermal maturity anomalies correlate with heterogeneities in the basement and are presumably caused by localized hydrothermal activity. NE and SE oriented faults potentially served as vents for hydrothermal fluids and provided migration pathways for large oil fields. An example oil field located upon the Krasnoleninsky Arch in the southwestern West Siberian Basin was investigated to understand the timing and interplay of the petroleum system elements including the activity of faults.
Three boreholes and two seismic sections were used to build 1D and 2D petroleum system models. Detailed boundary conditions were defined and thermal modeling was performed by matching calculated values to calibration data. Different scenarios of opened/closed faults were tested to determine the history of oil migration. Good calibration with basal heat flow was achieved from initially 95 mW/m2 in the Triassic and slowly decreasing to values between 60 and 70 mW/m2 until today. Modelled present-day surface heat flow varies between 70 and 78 mW/m2. While subsidence is rather continuous from the Early Cretaceous until the Late Eocene, the Lower Cretaceous stands out. This dynamic epoch exhibits fluctuating sedimentation rates and tectonic uplift, which resulted in surface exposure and in local erosional unconformities. NE and SE directed basement lineaments were reactivated mainly as strike-slip faults during the Barremian and the Aptian.
Late Jurassic oil-prone source rocks reached depths between 2,300 and 2,500 m and maximum temperature of 120 to 130 °C. Ro varies around 0.9 % and transformation ratios yield 55 to 75 %. Two peaks of petroleum generation were identified during the Barremian (ca. 120 Ma) and the Campanian (ca. 80 Ma). Since about 600 m of low-permeable rock separate the source rocks and the overlying reservoir rocks, we conclude that both pulses required open faults for successful migration and charge of our example oil field.
Determination of Stress Directions From the Scale of the Volga-Ural Region to the Local Scale of the Field in the Orenburg Region For Optimize the Development System
Authors: Korolkova Kseniy Petrovna , Nikiforova Anna Aleksandrovna 
Published: September 2020

Abstract
Study of changes of regional horizontal stress in the Orenburg region in order to optimize the development of Volga-Ural region oil fields has not been carried out before.
The research is aimed at obtaining the results of the connection between direct (azimuthal electric micro-lateral logging) and indirect (work wells, hydraulic fracturing, tracer studies) methods to determine the direction of maximum stress in a vast territory of two regions: Samara and Orenburg.
A regional map based on the systematized measurements of the azimuthal electric microimager was constructed. This map does not contradict the tectonic and geological concepts of the Devonian system formation, which is the main largest reserve for the Volga-Ural region fields.
A local analysis of the direct and indirect methods relationship to determine the direction of maximum stress at the level of two fields of the Pervomaisky group - G1 and RK1 was conducted. This analysis was performed due to the large amount of input information from indirect data and in order to confirm the distribution of values in the peripheral zone of the regional map, where the reliability of mapping is reduced.
As a result of localization, a relationship was revealed, which allowed us to scale the analysis methodology to the existing fields of Volga-Ural region and to increase the number of indirect studies (tracer studies), as a cheaper analogue to azimuthal electric microblock logging.
Positive conclusions on the interconnection of methods made it possible to optimize the development of a perspective area in the eastern part of the RK1 field with the recommended reorientation of the direction horizontal wellbores with the subsequent economic effect for the company.