N. Cheremisin, R. Shulga, A. Zagorovskiy, Y. Gilmanov, Alexey Valentinovich Kochetov
The laboratory study of the formation of residual oil saturation in a gas cap after active gas production from it and the penetration of oil from the underlying oil reservoir is currently not regulated in any way. Residual oil saturation in the gas cap was taken and is accepted, as a rule, from the correlation dependences with reservoir properties obtained from experiments on oil displacement from to the limit oil-saturated core samples. The use of similar correlations for the transition zone significantly underestimates the mobile oil reserves in such zones In this connection, the paper discusses the technology of physical modeling of the residual oil saturation in the gas cap after the penetration of oil into it and the issues related to the determination of the residual oil saturation in the transition zones of oil reservoirs. On a series of test experiments on core samples of a weakly consolidated reservoir of the Pokurovskaya formation carried out according to the method developed by the authors, it was shown that the values of residual oil saturation after the penetration of oil into the gas cap are significantly lower than for oil-saturated formations with similar properties. It is shown that such studies will make it possible to clarify the possible irreversible oil losses during the advanced development of gas caps and to revise the approaches to the development of oil reservoirs of gas-oil and oil-gas fields. Laboratory modeling and study of the process of oil penetration into a gas cap and its subsequent displacement by water or gas is relevant for almost 10% of Rosneft's current reserves.
{"title":"Residual Hydrocarbon Saturation in the Transition Zone and the Gas Cap","authors":"N. Cheremisin, R. Shulga, A. Zagorovskiy, Y. Gilmanov, Alexey Valentinovich Kochetov","doi":"10.2118/206585-ms","DOIUrl":"https://doi.org/10.2118/206585-ms","url":null,"abstract":"\u0000 The laboratory study of the formation of residual oil saturation in a gas cap after active gas production from it and the penetration of oil from the underlying oil reservoir is currently not regulated in any way. Residual oil saturation in the gas cap was taken and is accepted, as a rule, from the correlation dependences with reservoir properties obtained from experiments on oil displacement from to the limit oil-saturated core samples. The use of similar correlations for the transition zone significantly underestimates the mobile oil reserves in such zones\u0000 In this connection, the paper discusses the technology of physical modeling of the residual oil saturation in the gas cap after the penetration of oil into it and the issues related to the determination of the residual oil saturation in the transition zones of oil reservoirs. On a series of test experiments on core samples of a weakly consolidated reservoir of the Pokurovskaya formation carried out according to the method developed by the authors, it was shown that the values of residual oil saturation after the penetration of oil into the gas cap are significantly lower than for oil-saturated formations with similar properties.\u0000 It is shown that such studies will make it possible to clarify the possible irreversible oil losses during the advanced development of gas caps and to revise the approaches to the development of oil reservoirs of gas-oil and oil-gas fields. Laboratory modeling and study of the process of oil penetration into a gas cap and its subsequent displacement by water or gas is relevant for almost 10% of Rosneft's current reserves.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88525698","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The approaches of building and methods of using the digital core are currently developing rapidly. The use of these methods makes it possible to obtain petrophysical information by non-destructive methods quickly. Digital rock physics includes two main stages: constructing models and modeling various physical processes on the obtained models. Our work proposes using deep learning methods for mineral and pore space segmentation instead of classical methods such as threshold image processing. Deep neural networks have long been able to show their advantages in many areas of computer vision. This paper proposes and tests methods that help identify different minerals in images from a scanning electron microscope. We used images of rocks of the Achimov formation, which are arkoses, as samples. We tested various deep neural networks such as LinkNet, U-Net, ResUNet, and pix2pix and identified those that performed best in segmentation.
{"title":"Multi-Mineral Segmentation of SEM Images Using Deep Learning Techniques","authors":"V. Alekseev, D. Orlov, D. Koroteev","doi":"10.2118/206526-ms","DOIUrl":"https://doi.org/10.2118/206526-ms","url":null,"abstract":"\u0000 The approaches of building and methods of using the digital core are currently developing rapidly. The use of these methods makes it possible to obtain petrophysical information by non-destructive methods quickly.\u0000 Digital rock physics includes two main stages: constructing models and modeling various physical processes on the obtained models. Our work proposes using deep learning methods for mineral and pore space segmentation instead of classical methods such as threshold image processing. Deep neural networks have long been able to show their advantages in many areas of computer vision.\u0000 This paper proposes and tests methods that help identify different minerals in images from a scanning electron microscope. We used images of rocks of the Achimov formation, which are arkoses, as samples. We tested various deep neural networks such as LinkNet, U-Net, ResUNet, and pix2pix and identified those that performed best in segmentation.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85908851","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. V. Kazak, S. Panin, Andrei Mikhailovich Valenkov, Tsimur Donalovich Hiliazitdzinau
This work studies the rheological properties of aqueous solutions of acrylamide copolymers. The prevailing role of elastic properties over viscous properties in predicting the proppant suspension capacity of the resulting fracturing fluid is shown. Furthermore, the potential of the use of oscillatory rheometry for studying fracturing fluid stability is demonstrated.
{"title":"Development of Fracturing Fluids Based on Acrylamide Copolymers and Study of Their Physical and Technological Properties Using the Oscillatory Rheometry Methods","authors":"M. V. Kazak, S. Panin, Andrei Mikhailovich Valenkov, Tsimur Donalovich Hiliazitdzinau","doi":"10.2118/206638-ms","DOIUrl":"https://doi.org/10.2118/206638-ms","url":null,"abstract":"\u0000 This work studies the rheological properties of aqueous solutions of acrylamide copolymers. The prevailing role of elastic properties over viscous properties in predicting the proppant suspension capacity of the resulting fracturing fluid is shown. Furthermore, the potential of the use of oscillatory rheometry for studying fracturing fluid stability is demonstrated.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84888454","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Andrei Tsyhankou, Alyaksandr Kanyushenka, Alyaksandr Hrudzinin, Alyaksei Kudrashou
The results of the well 10s2-Savichskaya drilling, laboratory core research are set out. Based on the results of integration the latest methods of wire line survey, laboratory core samples research, seismic facies analysis, typical lithotypes of the Savichsko-Bobrovichi area rocks were identified, reservoir features were predicted, the prospects of inter-salt deposits for identifying accumulations of hydrocarbons in unconventional reservoirs were substantiated. A perspective zone was identified and recommendations for drilling a pilot bore were given.
{"title":"Specification of the Geological Structure of the Inter-Salt Sediments of the Savichskoye Area Based on the Results of Well ?10S2 Drilling and Performing 3D Seismic Surveys in Order to Assess the Prospects for Identifying Hydrocarbons in Low-Permeability Reservoirs","authors":"Andrei Tsyhankou, Alyaksandr Kanyushenka, Alyaksandr Hrudzinin, Alyaksei Kudrashou","doi":"10.2118/206596-ms","DOIUrl":"https://doi.org/10.2118/206596-ms","url":null,"abstract":"\u0000 The results of the well 10s2-Savichskaya drilling, laboratory core research are set out. Based on the results of integration the latest methods of wire line survey, laboratory core samples research, seismic facies analysis, typical lithotypes of the Savichsko-Bobrovichi area rocks were identified, reservoir features were predicted, the prospects of inter-salt deposits for identifying accumulations of hydrocarbons in unconventional reservoirs were substantiated. A perspective zone was identified and recommendations for drilling a pilot bore were given.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78285559","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Digital rock analysis has proven to be useful for the prediction of petrophysical properties of conventional reservoirs, where the pore space is captured well by a modern µCT scanner with a resolution of 1-5 µm. Nevertheless, this resolution is not enough to accurately capture the pore space of tight (low-permeable) rock samples. As a result, derived digital rock models do not reflect the real rock topology, and permeability predictions yield unreliable results. Our approach deploys high-contrast µCT scanning technique and Focused Ion Beam milling combined with Scanning Electron Microscopy to improve the quality of digital rock models and, hence, the permeability prediction. This workflow is successfully applied to a low-permeable rock sample of Achimov deposits. The computed permeability compares well to the experimental value.
{"title":"Application of High-Contrast µCT and FIB-SEM for the Improvement in the Permeability Prediction of Tight Rock Samples","authors":"A. Avdonin, M. Ebadi, V. Krutko","doi":"10.2118/206588-ms","DOIUrl":"https://doi.org/10.2118/206588-ms","url":null,"abstract":"\u0000 Digital rock analysis has proven to be useful for the prediction of petrophysical properties of conventional reservoirs, where the pore space is captured well by a modern µCT scanner with a resolution of 1-5 µm. Nevertheless, this resolution is not enough to accurately capture the pore space of tight (low-permeable) rock samples. As a result, derived digital rock models do not reflect the real rock topology, and permeability predictions yield unreliable results. Our approach deploys high-contrast µCT scanning technique and Focused Ion Beam milling combined with Scanning Electron Microscopy to improve the quality of digital rock models and, hence, the permeability prediction. This workflow is successfully applied to a low-permeable rock sample of Achimov deposits. The computed permeability compares well to the experimental value.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86696696","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Alexander Vitalyevich Tsarenko, V. Tarsky, Lisa Jane Robson
The objective of this article is to share an evaluation of the background, drilling outcomes and production and reservoir pressure impacts from two years of monitoring the first commingled up-dip SMART water injector drilled in the Piltun area of the Piltun-Astokhskoye offshore oil and gas field, located in Sakhalin, far east of Russia. The unique aspect of this water injector is that it was drilled into the up-dip gas caps of two separate reservoirs to provide pressure support to commingled oil producers, complementing the down-dip water injectors already in place. This article highlights some details of the well maturation decisions and expectations based on output of the dynamic modelling studies. Drilling outcomes and well performance is compared to expectations. Initial results of the surveillance programme and field data analysis based on a two-year monitoring period are discussed to show intermediate outcomes of up-dip water injection in the Piltun area. Finally, remaining questions and uncertainties are shared. Piltun-Astokhskoye is a complex multi-reservoir offshore oil and gas field with sizeable gas caps, significant heterogeneity both between and within reservoirs and a complex production history involving commingled oil producers and water injectors. Limited data is available to assess the impact of development decisions. Integrated analysis using multiple data sources and back-to-basics geology and reservoir engineering is required to understand how the reservoirs are responding to up-dip water injection, in order to predict future performance and make informed decisions to optimise the Piltun development over the long term. Surveillance data shows that up-dip water injection is effective in increasing reservoir pressure and oil recovery in one of the reservoirs, whilst having little impact on the other. Analysis shows that variable impact is due to the influence of gas cap size on up-dip water injection efficiency and the risk of trapped gas volumes due to water injection into the gas cap. The importance of integration between different sources of surveillance data and analytical tools to complete a comprehensive and reliable analysis is shown.
{"title":"Implementation and Intermediate Monitoring Outcomes of the First Commingled Up-Dip SMART Water Injection Well in PA-B Platform Piltun-Astokhskoye Offshore Oil and Gas Field","authors":"Alexander Vitalyevich Tsarenko, V. Tarsky, Lisa Jane Robson","doi":"10.2118/206503-ms","DOIUrl":"https://doi.org/10.2118/206503-ms","url":null,"abstract":"\u0000 The objective of this article is to share an evaluation of the background, drilling outcomes and production and reservoir pressure impacts from two years of monitoring the first commingled up-dip SMART water injector drilled in the Piltun area of the Piltun-Astokhskoye offshore oil and gas field, located in Sakhalin, far east of Russia.\u0000 The unique aspect of this water injector is that it was drilled into the up-dip gas caps of two separate reservoirs to provide pressure support to commingled oil producers, complementing the down-dip water injectors already in place. This article highlights some details of the well maturation decisions and expectations based on output of the dynamic modelling studies. Drilling outcomes and well performance is compared to expectations. Initial results of the surveillance programme and field data analysis based on a two-year monitoring period are discussed to show intermediate outcomes of up-dip water injection in the Piltun area. Finally, remaining questions and uncertainties are shared.\u0000 Piltun-Astokhskoye is a complex multi-reservoir offshore oil and gas field with sizeable gas caps, significant heterogeneity both between and within reservoirs and a complex production history involving commingled oil producers and water injectors. Limited data is available to assess the impact of development decisions. Integrated analysis using multiple data sources and back-to-basics geology and reservoir engineering is required to understand how the reservoirs are responding to up-dip water injection, in order to predict future performance and make informed decisions to optimise the Piltun development over the long term.\u0000 Surveillance data shows that up-dip water injection is effective in increasing reservoir pressure and oil recovery in one of the reservoirs, whilst having little impact on the other. Analysis shows that variable impact is due to the influence of gas cap size on up-dip water injection efficiency and the risk of trapped gas volumes due to water injection into the gas cap. The importance of integration between different sources of surveillance data and analytical tools to complete a comprehensive and reliable analysis is shown.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76105067","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Gubanova, Bulat A. Khabibullin, D. Orlov, D. Koroteev
To reduce inefficient costs and environmental risks, oil companies strive to optimize the process of hydrocarbon production at all stages of field development, including geological and technical works at wells. In particular, it is important to predict fluid production with high accuracy. 3D hydrodynamic modeling is a generally accepted technique for solving this problem. It provides reliable results but requires many input data, computational resources, and time for calculations. Since the decision-making process has to be reactive, it is necessary to develop a simultaneously precise and prompt predictive instrument for quick forecasts of liquid production. The most promising tools for these purposes are proxy models based on solving the material balance equation. They adapt to the existing historical data even without PVT properties and reservoir data. Some of the most popular approaches are proxy models such as Capacitance Resistance Models (CRM). CR-type model is a material balance-based flow model, which provides preferable transmissibility trends, the presence of sealing or leaking faults with compressibility effects in consideration, and dissipation between injector-producer pairs. It is a data-driven model with adjustable time constants and interwell connectivity parameters. Before the model tuning, all parameters must be initialized with analytical or random approximations, and then they can be found by an appropriate optimization procedure. Historical-based Capacitance Models can be applied to poorly studied fields. Besides, they give an opportunity to rapidly optimize field development strategy by making calculations with different well exploitation parameters. They only require historical data of hydrocarbon production volumes, injection profiles, and bottom-hole pressure dynamics as input data. One of the main is that properties in the interwell space are estimated approximately and considered to be constant throughout the entire development history. However, this is a weak assumption in the case of including well interventions and stimulations. Thus, the main goal of this work is to adjust coefficients online to changes in well operation modes, introducing new wells or shut-in the existing ones. Since the governing equation includes the considered CRM improvement, users can perform optimization over different timespans, including "special" intervals. As a result, weighting connectivity parameters of the model can be depicted on a map of well interactions versus time.
{"title":"Modified CR-Type Material Balance Model for Well Production Forecasts in Case of Well Treatments","authors":"A. Gubanova, Bulat A. Khabibullin, D. Orlov, D. Koroteev","doi":"10.2118/206511-ms","DOIUrl":"https://doi.org/10.2118/206511-ms","url":null,"abstract":"\u0000 To reduce inefficient costs and environmental risks, oil companies strive to optimize the process of hydrocarbon production at all stages of field development, including geological and technical works at wells. In particular, it is important to predict fluid production with high accuracy. 3D hydrodynamic modeling is a generally accepted technique for solving this problem. It provides reliable results but requires many input data, computational resources, and time for calculations. Since the decision-making process has to be reactive, it is necessary to develop a simultaneously precise and prompt predictive instrument for quick forecasts of liquid production. The most promising tools for these purposes are proxy models based on solving the material balance equation. They adapt to the existing historical data even without PVT properties and reservoir data. Some of the most popular approaches are proxy models such as Capacitance Resistance Models (CRM).\u0000 CR-type model is a material balance-based flow model, which provides preferable transmissibility trends, the presence of sealing or leaking faults with compressibility effects in consideration, and dissipation between injector-producer pairs. It is a data-driven model with adjustable time constants and interwell connectivity parameters. Before the model tuning, all parameters must be initialized with analytical or random approximations, and then they can be found by an appropriate optimization procedure. Historical-based Capacitance Models can be applied to poorly studied fields. Besides, they give an opportunity to rapidly optimize field development strategy by making calculations with different well exploitation parameters. They only require historical data of hydrocarbon production volumes, injection profiles, and bottom-hole pressure dynamics as input data. One of the main is that properties in the interwell space are estimated approximately and considered to be constant throughout the entire development history. However, this is a weak assumption in the case of including well interventions and stimulations.\u0000 Thus, the main goal of this work is to adjust coefficients online to changes in well operation modes, introducing new wells or shut-in the existing ones. Since the governing equation includes the considered CRM improvement, users can perform optimization over different timespans, including \"special\" intervals. As a result, weighting connectivity parameters of the model can be depicted on a map of well interactions versus time.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78206716","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper the simplified way is proposed for predicting the dynamics of liquid production and estimating the parameters of the oil reservoir using diagnostic curves, which are a generalization of analytical approaches, partially compared with the results of calculations on 3D simulation models and with actual well production data.
{"title":"Diagnostic Plots for Production Decline During the Transition of Oil Field Development From Depletion to Water Injection","authors":"V. Syrtlanov, Y. Golovatskiy, I. Ishimov","doi":"10.2118/206499-ms","DOIUrl":"https://doi.org/10.2118/206499-ms","url":null,"abstract":"\u0000 In this paper the simplified way is proposed for predicting the dynamics of liquid production and estimating the parameters of the oil reservoir using diagnostic curves, which are a generalization of analytical approaches, partially compared with the results of calculations on 3D simulation models and with actual well production data.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75143112","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. Khakimova, A. Isaeva, V. Dobrozhanskiy, Y. Podladchikov
We discuss numerical simulation of carbon dioxide injection considered by oil and gas companies. Complex behavior of multicomponent reservoir fluids mixed with carbon dioxide may cause the occurrence of vapor-liquid-liquid equilibria (VLLE), salt precipitation in aquifers, pore-clogging, etc. We propose a simple algorithm for phase equilibria calculations based on the minimization of the multicomponent system free energy. This algorithm can be used to calculate phase separations and component partitioning between the phases under various conditions (critical region, two- and three-phase equilibria, etc.). We demonstrate the applicability of the proposed algorithm in a series of calculations. We consider binary and ternary mixtures that include carbon dioxide and hydrocarbons. We examine the algorithm in two- and three-phase equilibrium calculations and compare its performance with the popular iterative fugacity equilibration technique. We show that both calculation techniques give near-identical results for the considered mixtures. Thus, we show that the free energy minimization algorithm can be used interchangeably with the fugacity equilibration technique for calculating phase equilibria. This algorithm is applicable for VLLE calculations, which is important when considering multicomponent reservoir fluids that include carbon dioxide.
{"title":"Direct Energy Minimization Algorithm for Numerical Simulation of Carbon Dioxide Injection","authors":"L. Khakimova, A. Isaeva, V. Dobrozhanskiy, Y. Podladchikov","doi":"10.2118/206611-ms","DOIUrl":"https://doi.org/10.2118/206611-ms","url":null,"abstract":"\u0000 We discuss numerical simulation of carbon dioxide injection considered by oil and gas companies. Complex behavior of multicomponent reservoir fluids mixed with carbon dioxide may cause the occurrence of vapor-liquid-liquid equilibria (VLLE), salt precipitation in aquifers, pore-clogging, etc. We propose a simple algorithm for phase equilibria calculations based on the minimization of the multicomponent system free energy. This algorithm can be used to calculate phase separations and component partitioning between the phases under various conditions (critical region, two- and three-phase equilibria, etc.). We demonstrate the applicability of the proposed algorithm in a series of calculations. We consider binary and ternary mixtures that include carbon dioxide and hydrocarbons. We examine the algorithm in two- and three-phase equilibrium calculations and compare its performance with the popular iterative fugacity equilibration technique. We show that both calculation techniques give near-identical results for the considered mixtures. Thus, we show that the free energy minimization algorithm can be used interchangeably with the fugacity equilibration technique for calculating phase equilibria. This algorithm is applicable for VLLE calculations, which is important when considering multicomponent reservoir fluids that include carbon dioxide.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75015615","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. A. Zubakin, A. Davydov, A. Gogolev, S. Chistyakov, Nikolay Alexandrovich Filatov, A. Boyev, V. Rukavishnikov
Non-separation measurement of a multiphase mixture coming from an oil well is traditionally considered a complex measurement, for which rather expensive solutions are used, including non-trivial maintenance. This work aims to describe a new technology in the area of measuring multiphase oil and gas-water mixture, which is being finalized by specialists of the Tomsk Polytechnic University for conducting pilot tests at the facilities of Zarubezhneft JSC, and to indicate a more informative level of measurement of oil and gas industry production, which allows measuring the amount of oil, gas and water with high precision without the use of radioactive sources and constriction devices. The purpose of measuring a multiphase mixture is to determine the amount of oil, gas and water. In order to do this, it is required to determine the total flow rate of the mixture and the distribution of the flow by substances and phases: oil gas, oil and formation water. The total flow rate in the developed multiphase X-ray flowmeter is based on cross-correlation analysis of radiograms from two linear detectors. Measurement of the component composition for the purpose of the distribution of the flow by substances and phases is carried out by the method of two-wave absorptiometry.
{"title":"Development of an Innovational Multiphase X-Ray Flowmeter","authors":"A. A. Zubakin, A. Davydov, A. Gogolev, S. Chistyakov, Nikolay Alexandrovich Filatov, A. Boyev, V. Rukavishnikov","doi":"10.2118/206472-ms","DOIUrl":"https://doi.org/10.2118/206472-ms","url":null,"abstract":"\u0000 Non-separation measurement of a multiphase mixture coming from an oil well is traditionally considered a complex measurement, for which rather expensive solutions are used, including non-trivial maintenance.\u0000 This work aims to describe a new technology in the area of measuring multiphase oil and gas-water mixture, which is being finalized by specialists of the Tomsk Polytechnic University for conducting pilot tests at the facilities of Zarubezhneft JSC, and to indicate a more informative level of measurement of oil and gas industry production, which allows measuring the amount of oil, gas and water with high precision without the use of radioactive sources and constriction devices.\u0000 The purpose of measuring a multiphase mixture is to determine the amount of oil, gas and water. In order to do this, it is required to determine the total flow rate of the mixture and the distribution of the flow by substances and phases: oil gas, oil and formation water. The total flow rate in the developed multiphase X-ray flowmeter is based on cross-correlation analysis of radiograms from two linear detectors. Measurement of the component composition for the purpose of the distribution of the flow by substances and phases is carried out by the method of two-wave absorptiometry.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78953844","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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