A. Gudz, I. Ilyasov, A. Podkorytov, M. Tomashevskiy, N. Glushchenko
The paper describes the basic features of the East-Messoyahskoe oil field that are important for efficient reservoir development, the key of which are high oil viscosity (111 cP), high heterogenieity and permeability contrast, and the presence of aquifer with a different strength. The review of the experience in proactive breakthrough risks identification is presented. The actual breakthroughs during waterflooding of the PK-13 reservoir of the East-Messoyahskoe oil field are described and analyzed. The backgrounds and regularities increasing the risks of breakthroughs are identified. The analytical calculations have been made and key influencing factors have been defined. Based on the obtained results, the methodology of the proactive breakthrough identification was developed. The methodology has been tested in the real conditions of the East-Messoyahskoe oil field. The first results have been received, which confirm the operational efficiency of the developed methodological approach. All wells were rated according to their breakthrough risk, and measures for operative and proactive breakthroughs risk management has been proposed. All listed are combined into a system which permits minimization of breakthrough risks and manages them for the increase of unconsolidated heavy oil reservoirs development efficiency.
{"title":"Challenging Water Channeling in Unconsolidated Heavy Oil Reservoirs: Risks and Management","authors":"A. Gudz, I. Ilyasov, A. Podkorytov, M. Tomashevskiy, N. Glushchenko","doi":"10.2118/206502-ms","DOIUrl":"https://doi.org/10.2118/206502-ms","url":null,"abstract":"\u0000 The paper describes the basic features of the East-Messoyahskoe oil field that are important for efficient reservoir development, the key of which are high oil viscosity (111 cP), high heterogenieity and permeability contrast, and the presence of aquifer with a different strength.\u0000 The review of the experience in proactive breakthrough risks identification is presented. The actual breakthroughs during waterflooding of the PK-13 reservoir of the East-Messoyahskoe oil field are described and analyzed. The backgrounds and regularities increasing the risks of breakthroughs are identified. The analytical calculations have been made and key influencing factors have been defined.\u0000 Based on the obtained results, the methodology of the proactive breakthrough identification was developed. The methodology has been tested in the real conditions of the East-Messoyahskoe oil field. The first results have been received, which confirm the operational efficiency of the developed methodological approach. All wells were rated according to their breakthrough risk, and measures for operative and proactive breakthroughs risk management has been proposed. All listed are combined into a system which permits minimization of breakthrough risks and manages them for the increase of unconsolidated heavy oil reservoirs development efficiency.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75750408","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}
Saltanat Koishymanova, Danil Kayashev, B. Schwanitz, Tolegen Sadvakassov, Y. Ponomarenko
The transition to a climate-neutral society is both an urgent technical challenge and yet long-term CAPEX heavy requiring huge investments from industry and governments. Major oil and gas (O&G) operators around the globe have already established their decarbonization targets and even though upstream accounts for two-thirds of total emissions in the petroleum industry, both new well construction designs, and improved workover operations are proving to be effective measures in minimizing greenhouse gas (GHG) emissions while being economically viable. A novel completion technology has been installed in 114 wells in Russia since 2018 to eliminate sustained annular casing pressure (SAP) throughout the lives of wells and combat the associated release of carbon dioxide (CO2) and methane into the atmosphere. Since methane is much more powerful and has a 28-34 times more global warming potential compared to CO2 over the hundreds of years, and 84-86 times more potent over a 20-year timeframe respectively, these types of simple, yet efficient solutions represents enormous benefits to operators in reducing their carbon taxes while tackling climate change. Moreover, the installation of this technology resulted in reliable downhole well integrity of traditionally problematic wells, without the need for subsequent squeeze cementing operations. These types of completion solutions set both in an open and cased hole, allow operators not just to customize their cementing program and meet regulatory approvals, but also greatly reduce their reported carbon emissions. A summary of the results and efficiencies achieved with these installations will be presented and will be compared to conventional technologies. In addition, more than 15,000 lightweight e-line intervention operations have been performed both in Russia and Kazakhstan since 2011 which contributed to fewer emissions of hazardous greenhouse gases into the air versus conventional coiled tubing operations. These types of light interventions use less diesel to operate and with fewer people and equipment, leave a smaller carbon footprint on each well location which in turn makes a difference when it comes to GHG emission reduction. A comparison breakdown of coiled tubing versus e-line mechanical interventions will be statistically analyzed. This paper will illustrate how these newer technologies contributed to GHG emission reduction and how simultaneously economical efficiencies were achieved during well completion and intervention activities through reduced rig time and faster job execution compared to conventional methods. It will also review case histories from fields across the region using these installations and analyze each method. The field data will present the development, installation, and operational sequence and explain how each setup was tailored to meet both specific operational needs and to reduce greenhouse emissions, mainly by minimizing gas flaring. Widespread implementation of such techn
{"title":"Minimization of Greenhouse Emissions in Russia and Kazakhstan Upstream Sector Through Optimized Well Construction Designs and Lightweight Mechanical E-Line Operations","authors":"Saltanat Koishymanova, Danil Kayashev, B. Schwanitz, Tolegen Sadvakassov, Y. Ponomarenko","doi":"10.2118/206609-ms","DOIUrl":"https://doi.org/10.2118/206609-ms","url":null,"abstract":"\u0000 The transition to a climate-neutral society is both an urgent technical challenge and yet long-term CAPEX heavy requiring huge investments from industry and governments. Major oil and gas (O&G) operators around the globe have already established their decarbonization targets and even though upstream accounts for two-thirds of total emissions in the petroleum industry, both new well construction designs, and improved workover operations are proving to be effective measures in minimizing greenhouse gas (GHG) emissions while being economically viable. A novel completion technology has been installed in 114 wells in Russia since 2018 to eliminate sustained annular casing pressure (SAP) throughout the lives of wells and combat the associated release of carbon dioxide (CO2) and methane into the atmosphere. Since methane is much more powerful and has a 28-34 times more global warming potential compared to CO2 over the hundreds of years, and 84-86 times more potent over a 20-year timeframe respectively, these types of simple, yet efficient solutions represents enormous benefits to operators in reducing their carbon taxes while tackling climate change. Moreover, the installation of this technology resulted in reliable downhole well integrity of traditionally problematic wells, without the need for subsequent squeeze cementing operations. These types of completion solutions set both in an open and cased hole, allow operators not just to customize their cementing program and meet regulatory approvals, but also greatly reduce their reported carbon emissions. A summary of the results and efficiencies achieved with these installations will be presented and will be compared to conventional technologies.\u0000 In addition, more than 15,000 lightweight e-line intervention operations have been performed both in Russia and Kazakhstan since 2011 which contributed to fewer emissions of hazardous greenhouse gases into the air versus conventional coiled tubing operations. These types of light interventions use less diesel to operate and with fewer people and equipment, leave a smaller carbon footprint on each well location which in turn makes a difference when it comes to GHG emission reduction. A comparison breakdown of coiled tubing versus e-line mechanical interventions will be statistically analyzed.\u0000 This paper will illustrate how these newer technologies contributed to GHG emission reduction and how simultaneously economical efficiencies were achieved during well completion and intervention activities through reduced rig time and faster job execution compared to conventional methods. It will also review case histories from fields across the region using these installations and analyze each method. The field data will present the development, installation, and operational sequence and explain how each setup was tailored to meet both specific operational needs and to reduce greenhouse emissions, mainly by minimizing gas flaring. Widespread implementation of such techn","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75902013","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}
Roman Yurievich Ponomarev, Vladimir Evgenievich Vershinin
The article discusses the results of long-term forecasting of non-stationary technological modes of production wells using neural network modeling methods. The main difficulty in predicting unsteady modes is to reproduce the response of producing wells to a sharp change in the mode of one of the wells. Such jumps, as a rule, lead to a rapid increase in the forecast error. Training and forecasting of modes was carried out on the data of numerical hydrodynamic modeling. Two fields with significantly different properties, the number of wells and their modes of operation were selected as objects of modeling. Non-stationarity was set by changing the regime on one or several production wells at different points in time. The LSTM recurrent neural network carried out forecasting of production technological parameters. This made it possible to take into account the time-lagging influence of the wells on each other. It is shown that the LSTM neural network allows predicting unsteady technological modes of well operation with an accuracy of up to 5% for a period of 10 years. The solution of the problem of optimization of oil production is considered on the example of one of the models. It is shown that the optimal solution found by the neural network differs from the solution found by hydrodynamic modeling by 5%. At the same time, a significant gain in calculation time was achieved.
{"title":"Long-Term Forecasting and Optimization of Non-Stationary Well Operation Modes Through Neural Networks Simulation","authors":"Roman Yurievich Ponomarev, Vladimir Evgenievich Vershinin","doi":"10.2118/206529-ms","DOIUrl":"https://doi.org/10.2118/206529-ms","url":null,"abstract":"\u0000 The article discusses the results of long-term forecasting of non-stationary technological modes of production wells using neural network modeling methods. The main difficulty in predicting unsteady modes is to reproduce the response of producing wells to a sharp change in the mode of one of the wells. Such jumps, as a rule, lead to a rapid increase in the forecast error. Training and forecasting of modes was carried out on the data of numerical hydrodynamic modeling. Two fields with significantly different properties, the number of wells and their modes of operation were selected as objects of modeling. Non-stationarity was set by changing the regime on one or several production wells at different points in time. The LSTM recurrent neural network carried out forecasting of production technological parameters. This made it possible to take into account the time-lagging influence of the wells on each other. It is shown that the LSTM neural network allows predicting unsteady technological modes of well operation with an accuracy of up to 5% for a period of 10 years. The solution of the problem of optimization of oil production is considered on the example of one of the models. It is shown that the optimal solution found by the neural network differs from the solution found by hydrodynamic modeling by 5%. At the same time, a significant gain in calculation time was achieved.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72690555","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}
K. Goridko, R. Khabibullin, V. Verbitsky, A. R. Shabonas, G. Kazakbaeva
One of the most common complications in the operation of wells with electric submersible pumps (ESP) is the presence of free gas in the produced well product. The work considers a model of ESP operation taking into account a large share of free gas in the flow obtained on the basis of bench tests and its applicability for analyzing the operation of real producing wells equipped with ESPs. Tests of ESP5-50 (118 radial stages) with model gas-liquid mixtures in a wide range of inlet gas volume-flow rate (0-60%), inlet pressure (0.6-2.1 MPa), shaft speed (2400-3600 rpm) with simultaneous pressure measurement along the pump length and direct measuring of power at the shaft by means of motor weights were performed at the oilfield development and operation department. Mathematical model is obtained by means of regression analysis of experimentally received characteristics of ESPs on gas liquid mixtures; a simple engineering method of calculating the degradation of ESPs characteristics by flow, head and power is suggested. The experience of building similar models described in the literature was taken into account. Experimental studies and creation of a mathematical model of ESP were carried out during Kirill Goridko's PhD thesis. As a result of the research we obtained the degradation dependencies of the pump's delivery and the head of ESP while pumping mixtures of different foam capacity, which simulate the pump operation in low and high watercut wells. The patterns of delivery and head coefficients depending on the zone (left, optimum, right) of ESP characteristic are revealed. The degradation of ESP power during pumping gas liquid mixture is clarified, which allows to calculate more accurately the specific energy consumption of well products lifting. The developed method of recalculation of the pressure and power characteristics of ESPs is implemented in the form of calculation modules designed for engineering calculations in oil production. The proposed tool has been tested on the data of the Western Siberia fields while analyzing the operation of wells with high gas content in the produced product. Calculation modules have been made publicly available. A new simple engineering method was developed to account for the degradation of the pressure and flow and power characteristics of ESPs for low- and medium-rate wells based on a large number of benchmark studies. Оbtained degradation dependences are programmed in the form of calculation modules, which allows to analyze the operation of a large number of wells on the basis of their technological mode, as well as to propose optimization measures to change the ESP operation at a higher level.
{"title":"New Methodology for Calculating the Impact of High Free Gas Content in the Flow on ESP Characteristics for the West Siberia Fields","authors":"K. Goridko, R. Khabibullin, V. Verbitsky, A. R. Shabonas, G. Kazakbaeva","doi":"10.2118/206468-ms","DOIUrl":"https://doi.org/10.2118/206468-ms","url":null,"abstract":"\u0000 One of the most common complications in the operation of wells with electric submersible pumps (ESP) is the presence of free gas in the produced well product. The work considers a model of ESP operation taking into account a large share of free gas in the flow obtained on the basis of bench tests and its applicability for analyzing the operation of real producing wells equipped with ESPs.\u0000 Tests of ESP5-50 (118 radial stages) with model gas-liquid mixtures in a wide range of inlet gas volume-flow rate (0-60%), inlet pressure (0.6-2.1 MPa), shaft speed (2400-3600 rpm) with simultaneous pressure measurement along the pump length and direct measuring of power at the shaft by means of motor weights were performed at the oilfield development and operation department. Mathematical model is obtained by means of regression analysis of experimentally received characteristics of ESPs on gas liquid mixtures; a simple engineering method of calculating the degradation of ESPs characteristics by flow, head and power is suggested. The experience of building similar models described in the literature was taken into account. Experimental studies and creation of a mathematical model of ESP were carried out during Kirill Goridko's PhD thesis.\u0000 As a result of the research we obtained the degradation dependencies of the pump's delivery and the head of ESP while pumping mixtures of different foam capacity, which simulate the pump operation in low and high watercut wells. The patterns of delivery and head coefficients depending on the zone (left, optimum, right) of ESP characteristic are revealed. The degradation of ESP power during pumping gas liquid mixture is clarified, which allows to calculate more accurately the specific energy consumption of well products lifting. The developed method of recalculation of the pressure and power characteristics of ESPs is implemented in the form of calculation modules designed for engineering calculations in oil production. The proposed tool has been tested on the data of the Western Siberia fields while analyzing the operation of wells with high gas content in the produced product. Calculation modules have been made publicly available.\u0000 A new simple engineering method was developed to account for the degradation of the pressure and flow and power characteristics of ESPs for low- and medium-rate wells based on a large number of benchmark studies. Оbtained degradation dependences are programmed in the form of calculation modules, which allows to analyze the operation of a large number of wells on the basis of their technological mode, as well as to propose optimization measures to change the ESP operation at a higher level.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"117 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78158843","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}
Nikolai Pavlovich Sarapulov, Maxim Valerevich Vasin, Andranik Sedrakovich Palandzhyants, Evgeni Alexandrovich Tambovstev, R. Khabibullin
The article is devoted to the selection of a specialized configuration of submersible equipment to minimize downhole pressure in order to intensify the flow of fluid to the wells of Gazpromneft-Orenburg. The depth of the wells and the design features of the well do not allow sufficient depth of the pumping equipment (top of the perforation interval 3800-4200 m). In addition, the operation of the fund is complicated by abnormally low reservoir pressures (60-120 at), low filtration-capacity properties and high linear pressures of single-standing wells (20-30 at). To increase the productivity of wells, the ESP layout was used with a two-way engine, two submersible pumps and a shank. The layout is chosen in such a way as to reduce the density of the liquid column under the pump due to the circulation of the liquid by the lower pump. A special feature of the design was the selection of the length and the limit of the descent of the shank, the ratio of performance and pressure of the upper and lower pumps and a number of pre-connected devices as part of the layout. Pilot tests were conducted at three wells of the Gazpromneft-Orenburg field. After the installation and commissioning work in the process of bringing the wells to the established mode, the features of the ESP that differ from the standard operation, leading to an increase in the period of stable well production, were revealed. According to the results of the tests, an increase in the oil flow rate of an average of 16 tons per day was obtained. The study of the characteristics of a complete installation directly on the test wells allowed us to determine the technical capabilities of the equipment, the volume-flow characteristics of the fluid under the pump and PVT. The aspects of natural separation and free gas content at the inlet of both pumps are studied, which is also a boundary condition for well intensification. The tests allowed us to assess the technological limit of the layout with two ESP in the conditions of the Gazpromneft-Orenburg field. In contrast to other options for the operation of hard-to-recover wells, the proposed layout has a number of advantages, such as a minimum increase in the cost of construction, simplicity of construction, which ensures high operating time of equipment and low specific energy consumption. Based on the results of testing the pilot installations, a decision was made to replicate this approach in the Company.
{"title":"Specialized ESP Layouts for the Operation of Deep Wells Confined to the Category of Hard-to-Recover Reserves","authors":"Nikolai Pavlovich Sarapulov, Maxim Valerevich Vasin, Andranik Sedrakovich Palandzhyants, Evgeni Alexandrovich Tambovstev, R. Khabibullin","doi":"10.2118/206467-ms","DOIUrl":"https://doi.org/10.2118/206467-ms","url":null,"abstract":"\u0000 The article is devoted to the selection of a specialized configuration of submersible equipment to minimize downhole pressure in order to intensify the flow of fluid to the wells of Gazpromneft-Orenburg. The depth of the wells and the design features of the well do not allow sufficient depth of the pumping equipment (top of the perforation interval 3800-4200 m). In addition, the operation of the fund is complicated by abnormally low reservoir pressures (60-120 at), low filtration-capacity properties and high linear pressures of single-standing wells (20-30 at).\u0000 To increase the productivity of wells, the ESP layout was used with a two-way engine, two submersible pumps and a shank. The layout is chosen in such a way as to reduce the density of the liquid column under the pump due to the circulation of the liquid by the lower pump. A special feature of the design was the selection of the length and the limit of the descent of the shank, the ratio of performance and pressure of the upper and lower pumps and a number of pre-connected devices as part of the layout.\u0000 Pilot tests were conducted at three wells of the Gazpromneft-Orenburg field. After the installation and commissioning work in the process of bringing the wells to the established mode, the features of the ESP that differ from the standard operation, leading to an increase in the period of stable well production, were revealed. According to the results of the tests, an increase in the oil flow rate of an average of 16 tons per day was obtained. The study of the characteristics of a complete installation directly on the test wells allowed us to determine the technical capabilities of the equipment, the volume-flow characteristics of the fluid under the pump and PVT. The aspects of natural separation and free gas content at the inlet of both pumps are studied, which is also a boundary condition for well intensification.\u0000 The tests allowed us to assess the technological limit of the layout with two ESP in the conditions of the Gazpromneft-Orenburg field. In contrast to other options for the operation of hard-to-recover wells, the proposed layout has a number of advantages, such as a minimum increase in the cost of construction, simplicity of construction, which ensures high operating time of equipment and low specific energy consumption. Based on the results of testing the pilot installations, a decision was made to replicate this approach in the Company.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81648019","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}
Mojtaba Rezaei Koochi, S. Mehrabi-Kalajahi, M. Varfolomeev, Vladislav Vladimirovich Savelev, E. Ziganshin, R. Kadyrov, I. N. Shamanov, Ranel I. Galeev
This work is devoted to investigate the ability of thermal shocking to create fractures in rock samples and thermal cracking of heavy crude oil structure. In order to study the thermobaric characterizations of catalytic and thermal decomposition reaction of binary mixture (BM), a series of experiments was designed in high-temperature and high-pressure reactor (HTHP) and the time to reach the maximum temperature and pressure were monitored. Before and after the experiments, core samples were scanned by 4D tomography. In addition, SARA analysis was done to study the effect of thermal shocking on heavy oil composition. The results showed that using BiMTheCh, the temperature in the reaction zone was increased up to 273 °C during very short time (2 seconds) after activation of the reaction. Either, the pressure was increased up to 129 atm. As results showed, the simultaneous sudden increase in temperature and pressure creates a thermal shock which reduces breakdown pressure from 235 to 12 atm. Computed scanning tomography results confirmed formation of new fractures on the surface of core samples. Results of the SARA analysis also confirmed that the molecular structure of heavy oil due to the binary mixture's reaction was changed. Sharp increase in pressure and temperature induced transformation of heavy components of crude oil such as asphaltenes into lighter components such as saturates. Generally, the binary mixture technology can be used as a new high-efficient and eco-friendly technology for enhanced heavy oil recovery from tight heavy oil reservoirs.
{"title":"Induced Thermal Shocking by BiMTheCh Technology as a New Approach for Enhanced Oil Recovery from Tight Reservoirs with Heavy Oil","authors":"Mojtaba Rezaei Koochi, S. Mehrabi-Kalajahi, M. Varfolomeev, Vladislav Vladimirovich Savelev, E. Ziganshin, R. Kadyrov, I. N. Shamanov, Ranel I. Galeev","doi":"10.2118/206414-ms","DOIUrl":"https://doi.org/10.2118/206414-ms","url":null,"abstract":"\u0000 This work is devoted to investigate the ability of thermal shocking to create fractures in rock samples and thermal cracking of heavy crude oil structure. In order to study the thermobaric characterizations of catalytic and thermal decomposition reaction of binary mixture (BM), a series of experiments was designed in high-temperature and high-pressure reactor (HTHP) and the time to reach the maximum temperature and pressure were monitored. Before and after the experiments, core samples were scanned by 4D tomography. In addition, SARA analysis was done to study the effect of thermal shocking on heavy oil composition. The results showed that using BiMTheCh, the temperature in the reaction zone was increased up to 273 °C during very short time (2 seconds) after activation of the reaction. Either, the pressure was increased up to 129 atm. As results showed, the simultaneous sudden increase in temperature and pressure creates a thermal shock which reduces breakdown pressure from 235 to 12 atm. Computed scanning tomography results confirmed formation of new fractures on the surface of core samples. Results of the SARA analysis also confirmed that the molecular structure of heavy oil due to the binary mixture's reaction was changed. Sharp increase in pressure and temperature induced transformation of heavy components of crude oil such as asphaltenes into lighter components such as saturates. Generally, the binary mixture technology can be used as a new high-efficient and eco-friendly technology for enhanced heavy oil recovery from tight heavy oil reservoirs.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84763551","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}
Monitoring of production rates is essential for reservoir management, history matching, and production optimization. Traditionally, such information is provided by multiphase flow meters or test separators. The growth of the availability of data, combined with the rapid development of computational resources, enabled the inception of digital techniques, which estimate oil, gas, and water rates indirectly. This paper discusses the application of continuous deep learning models, capable of reproducing multiphase flow dynamics for production monitoring purposes. This technique combines time evolution properties of a dynamical system and the ability of neural networks to quantitively describe poorly understood multiphase phenomena and can be considered as a hybrid solution between data-driven and mechanistic approaches. The continuous latent ordinary differential equation (Latent ODE) approach is compared to other known machine learning methods, such as linear regression, ensemble-based model, and recurrent neural network. In this work, the application of Latent ordinary differential equations for the problem of multiphase flow rate estimation is introduced. The considered example refers to a scenario, where the topside oil, gas, and water flow rates are estimated using the data from several downhole pressure sensors. The predictive capabilities of different types of machine learning and deep learning instruments are explored using simulated production data from a multiphase flow simulator. The results demonstrate the satisfactory performance of the continuous deep learning models in comparison to other machine learning methods in terms of accuracy, where the normalized root mean squared error (RMSE) and mean absolute error (MAE) of prediction below 5% were achieved. While LODE demonstrates the significant time required to train the model, it outperforms other methods for irregularly sampled time-series, which makes it especially attractive to forecast values of multiphase rates.
{"title":"Intelligent Production Monitoring with Continuous Deep Learning Models","authors":"A. Gryzlov, S. Safonov, M. Arsalan","doi":"10.2118/206525-ms","DOIUrl":"https://doi.org/10.2118/206525-ms","url":null,"abstract":"\u0000 Monitoring of production rates is essential for reservoir management, history matching, and production optimization. Traditionally, such information is provided by multiphase flow meters or test separators. The growth of the availability of data, combined with the rapid development of computational resources, enabled the inception of digital techniques, which estimate oil, gas, and water rates indirectly. This paper discusses the application of continuous deep learning models, capable of reproducing multiphase flow dynamics for production monitoring purposes. This technique combines time evolution properties of a dynamical system and the ability of neural networks to quantitively describe poorly understood multiphase phenomena and can be considered as a hybrid solution between data-driven and mechanistic approaches. The continuous latent ordinary differential equation (Latent ODE) approach is compared to other known machine learning methods, such as linear regression, ensemble-based model, and recurrent neural network.\u0000 In this work, the application of Latent ordinary differential equations for the problem of multiphase flow rate estimation is introduced. The considered example refers to a scenario, where the topside oil, gas, and water flow rates are estimated using the data from several downhole pressure sensors. The predictive capabilities of different types of machine learning and deep learning instruments are explored using simulated production data from a multiphase flow simulator.\u0000 The results demonstrate the satisfactory performance of the continuous deep learning models in comparison to other machine learning methods in terms of accuracy, where the normalized root mean squared error (RMSE) and mean absolute error (MAE) of prediction below 5% were achieved. While LODE demonstrates the significant time required to train the model, it outperforms other methods for irregularly sampled time-series, which makes it especially attractive to forecast values of multiphase rates.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90759635","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}
V. Zubkov, P. Molodykh, I. Goncharov, V. Samoilenko, S. Fadeeva
The article presents the results of two-year of research aimed at replenishing the resource and raw material base of the northwestern part of the Tomsk region. The practical application possibilities of basin modeling at the prospecting and exploratory stages of geological study of the subsurface are illustrated. The research was divided into two phases. The first of them has sub-regional coverage and includes an area of 25,000 km2 bounded by the Chkalovsky oil and gas condensate field in the southeast and the administrative boundaries of Tomsk Oblast in the northwest. The section is confined to the Alexandrovsky arch, covers part of the Koltogorsko-Nyurolsky chute and the eastern periclinal of the Nizhnevartovsky arch. At the first stage, a three-dimensional model of oil-and-gas bearing basin formation was created, the tasks of which were to replenish the history of generation and formation of ideas about the ways of hydrocarbon migration. The basin submergence has been reconstructed here and the thermal flow history has been restored. The uneven intensity of heat flow at the bottom of the sedimentary cover over the area is explained by tectonic processes and is complicated by a massive granitoid intrusion. In JSC "Tomsk Petroleum institute", the knowledge base of geochemical features of oil-and-gas source rocks and oils of Western Siberia was formed for years, which allowed to use their own kinetic spectra for the surveyed region. To calibrate the paleotemperatures, both the optical characteristics of vitrinite coals and the indicators of the geochemical properties of organic matter of the Bazhenov formation (4/1 MDBT and Tmax) were used. As a result, the conclusion about the presence of two generation centers of different nature was made, the time and volume of oil generation by organic matter of the Bazhenov formation were predicted. Next, the modeling parameters of hydrocarbon migration and accumulation are described. Modeling shows that the primary migration occurs due to the emergence of abnormally high pore pressure during the generation of hydrocarbons and fluid autofracture of the oil and gas source rock. The results of calculations of secondary migration by two different methods are compared. Despite a number of limitations, the results obtained show a fairly high convergence to real data. At the second stage, on the basis of the regional (parent) model a local daughter model of the formation of the Traygorodsko-Kondakovskoye field within the area of 480 km2 covered by 3D seismic exploration was plotted. The rationale for the necessity and description of the results of additional special geochemical studies of fluids and oil source rock, carried out before starting to build a detailed model of the local stage, is given. The article outlines the basic parameters and gives the differences between the local model and the parent model. Conclusions are made about the possibility of assessing the conductive properties of fault in th
{"title":"Basin Modeling as a Tool for Research of Regional Oil and Gas Generation Processes and the Possibility of Replacement of Oil and Gas Riches Illustrated through Traygorodsko-Kondakovskoye Oil Field","authors":"V. Zubkov, P. Molodykh, I. Goncharov, V. Samoilenko, S. Fadeeva","doi":"10.2118/206598-ms","DOIUrl":"https://doi.org/10.2118/206598-ms","url":null,"abstract":"\u0000 The article presents the results of two-year of research aimed at replenishing the resource and raw material base of the northwestern part of the Tomsk region. The practical application possibilities of basin modeling at the prospecting and exploratory stages of geological study of the subsurface are illustrated.\u0000 The research was divided into two phases. The first of them has sub-regional coverage and includes an area of 25,000 km2 bounded by the Chkalovsky oil and gas condensate field in the southeast and the administrative boundaries of Tomsk Oblast in the northwest. The section is confined to the Alexandrovsky arch, covers part of the Koltogorsko-Nyurolsky chute and the eastern periclinal of the Nizhnevartovsky arch. At the first stage, a three-dimensional model of oil-and-gas bearing basin formation was created, the tasks of which were to replenish the history of generation and formation of ideas about the ways of hydrocarbon migration.\u0000 The basin submergence has been reconstructed here and the thermal flow history has been restored. The uneven intensity of heat flow at the bottom of the sedimentary cover over the area is explained by tectonic processes and is complicated by a massive granitoid intrusion.\u0000 In JSC \"Tomsk Petroleum institute\", the knowledge base of geochemical features of oil-and-gas source rocks and oils of Western Siberia was formed for years, which allowed to use their own kinetic spectra for the surveyed region. To calibrate the paleotemperatures, both the optical characteristics of vitrinite coals and the indicators of the geochemical properties of organic matter of the Bazhenov formation (4/1 MDBT and Tmax) were used. As a result, the conclusion about the presence of two generation centers of different nature was made, the time and volume of oil generation by organic matter of the Bazhenov formation were predicted.\u0000 Next, the modeling parameters of hydrocarbon migration and accumulation are described. Modeling shows that the primary migration occurs due to the emergence of abnormally high pore pressure during the generation of hydrocarbons and fluid autofracture of the oil and gas source rock. The results of calculations of secondary migration by two different methods are compared. Despite a number of limitations, the results obtained show a fairly high convergence to real data.\u0000 At the second stage, on the basis of the regional (parent) model a local daughter model of the formation of the Traygorodsko-Kondakovskoye field within the area of 480 km2 covered by 3D seismic exploration was plotted.\u0000 The rationale for the necessity and description of the results of additional special geochemical studies of fluids and oil source rock, carried out before starting to build a detailed model of the local stage, is given.\u0000 The article outlines the basic parameters and gives the differences between the local model and the parent model. Conclusions are made about the possibility of assessing the conductive properties of fault in th","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74447750","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. Voloshin, N. Nifantiev, M. Egorov, R. Alimbekov, V. Dokichev
The effect of biodegradable polysaccharides – sodium (NaCMC) and ethanolammonium salts of carboxymethylcellulose, dextran and arabinogalactan on the process of gas hydrate formation was studied in order to search for new "green" inhibitors of low-concentration gas hydrate formation. The ability of polysaccharides to inhibit gas hydrate formation was studied in a quasi-equilibrium thermodynamic experiment. A mixture of hydrocarbon gases with a composition typical of the composition of petroleum gas and containing 78% methane was used as a gas-hydrate-forming model medium. It was found that in concentrations of 0.005, 0.0065 and 0.008%, dextran, NaCMC and arabinogalactan as thermodynamic inhibitors exceed methanol by 170-270 times in inhibitory properties. Dextran is superior to NaCMC and arabinogalactan in terms of inhibition efficiency, reduction of gas hydrate formation rate and induction time. Since with an increase in the concentration of polysaccharides, the pressure drop of gas hydrate formation increases and the rate of formation of gas hydrates decreases according to the mechanism of action, the studied polysaccharides can be attributed to both thermodynamic and kinetic inhibitors. It is established that the molecular weight of water-soluble polysaccharides has a significant effect on their inhibitory properties. A polysaccharide with a molecular weight of 250,000 demonstrated the highest inhibitory activity among the studied samples of NaCMC, which is 400 times more effective than methanol. NaCMC with a mass of 700 thousand did not have any effect on the formation of hydrates. Among the ethanolammonium salts, the monoethanolammonium salt CMC showed the greatest effectiveness in inhibiting the formation of tetrahydrofuran hydrates. An increase in its concentration from 0.02 to 0.1% leads to an increase in the induction time required for the nucleation and subsequent growth of crystals by 10 times. When switching from mono - to di - and triethanolammonium salts of carboxymethylcellulose, the inhibition efficiency decreases. It is shown that sodium and ethanolammonium salts of carboxymethylcellulose, arabinogalactan and dextran are promising for creating new "green" highly effective inhibitors of gas hydrate formation on their basis. The results of laboratory and field tests of the preparative form of the "green" gas hydrate formation inhibitor at the fields of Western Siberia are presented. It was found that at dosages of 500 g/m3 or less, there is no formation of hydrate plugs in the annulus of wells.
{"title":"Development and Implementation of Green Inhibitors of Gas Hydrate Formation in the Fields of Western Siberia","authors":"A. Voloshin, N. Nifantiev, M. Egorov, R. Alimbekov, V. Dokichev","doi":"10.2118/206470-ms","DOIUrl":"https://doi.org/10.2118/206470-ms","url":null,"abstract":"\u0000 The effect of biodegradable polysaccharides – sodium (NaCMC) and ethanolammonium salts of carboxymethylcellulose, dextran and arabinogalactan on the process of gas hydrate formation was studied in order to search for new \"green\" inhibitors of low-concentration gas hydrate formation. The ability of polysaccharides to inhibit gas hydrate formation was studied in a quasi-equilibrium thermodynamic experiment. A mixture of hydrocarbon gases with a composition typical of the composition of petroleum gas and containing 78% methane was used as a gas-hydrate-forming model medium. It was found that in concentrations of 0.005, 0.0065 and 0.008%, dextran, NaCMC and arabinogalactan as thermodynamic inhibitors exceed methanol by 170-270 times in inhibitory properties. Dextran is superior to NaCMC and arabinogalactan in terms of inhibition efficiency, reduction of gas hydrate formation rate and induction time. Since with an increase in the concentration of polysaccharides, the pressure drop of gas hydrate formation increases and the rate of formation of gas hydrates decreases according to the mechanism of action, the studied polysaccharides can be attributed to both thermodynamic and kinetic inhibitors. It is established that the molecular weight of water-soluble polysaccharides has a significant effect on their inhibitory properties. A polysaccharide with a molecular weight of 250,000 demonstrated the highest inhibitory activity among the studied samples of NaCMC, which is 400 times more effective than methanol. NaCMC with a mass of 700 thousand did not have any effect on the formation of hydrates. Among the ethanolammonium salts, the monoethanolammonium salt CMC showed the greatest effectiveness in inhibiting the formation of tetrahydrofuran hydrates. An increase in its concentration from 0.02 to 0.1% leads to an increase in the induction time required for the nucleation and subsequent growth of crystals by 10 times. When switching from mono - to di - and triethanolammonium salts of carboxymethylcellulose, the inhibition efficiency decreases. It is shown that sodium and ethanolammonium salts of carboxymethylcellulose, arabinogalactan and dextran are promising for creating new \"green\" highly effective inhibitors of gas hydrate formation on their basis. The results of laboratory and field tests of the preparative form of the \"green\" gas hydrate formation inhibitor at the fields of Western Siberia are presented. It was found that at dosages of 500 g/m3 or less, there is no formation of hydrate plugs in the annulus of wells.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84787369","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}
V. E. Tkacheva, A. Markin, Ignaty Andreevich Markin, Alexandr Yuryevich Presnyakov
Complications associated with a corrosive environment, according to Rosneft's data as of 01.01.2020, are among the prevailing at oil and gas production facilities and rank fourth among other factors complicating production - 12% the complicated mechanized wells. Failures due to corrosion are the second largest complicating factors. Based on the results of approbation, the article proposes a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and pipelines of oil gathering systems. Based on the approbation results, a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and oil gathering pipelines systems is proposed in the article. The proposed technique is realizable according to the results one of "traditional" methods the corrosion monitoring - weight (or gravimetric). The approbation results and application possibility the technique in the pilot tests process in assessing the protective ability of corrosion inhibitors and the selection the effective dosages in relation to local damages, which are the main cause the oilfield equipment failures according the factor "Corrosive aggressiveness" (one of the complicating factors in terms of gradation, adopted in the Rosneft Company regulations). On practical examples the oilfield equipment operation, the results of corrosion monitoring and the summary statistics the corrosive stock of wells (using the example of an oil Company), the current situation with respect to this type of complication and relevance the issue under consideration is shown.
{"title":"The Local Corrosion Rate Determination According to Weight Measurements Corrosion Coupons in Oilfield Conditions","authors":"V. E. Tkacheva, A. Markin, Ignaty Andreevich Markin, Alexandr Yuryevich Presnyakov","doi":"10.2118/206477-ms","DOIUrl":"https://doi.org/10.2118/206477-ms","url":null,"abstract":"\u0000 Complications associated with a corrosive environment, according to Rosneft's data as of 01.01.2020, are among the prevailing at oil and gas production facilities and rank fourth among other factors complicating production - 12% the complicated mechanized wells. Failures due to corrosion are the second largest complicating factors. Based on the results of approbation, the article proposes a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and pipelines of oil gathering systems. Based on the approbation results, a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and oil gathering pipelines systems is proposed in the article. The proposed technique is realizable according to the results one of \"traditional\" methods the corrosion monitoring - weight (or gravimetric). The approbation results and application possibility the technique in the pilot tests process in assessing the protective ability of corrosion inhibitors and the selection the effective dosages in relation to local damages, which are the main cause the oilfield equipment failures according the factor \"Corrosive aggressiveness\" (one of the complicating factors in terms of gradation, adopted in the Rosneft Company regulations). On practical examples the oilfield equipment operation, the results of corrosion monitoring and the summary statistics the corrosive stock of wells (using the example of an oil Company), the current situation with respect to this type of complication and relevance the issue under consideration is shown.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89216692","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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