Ying Gao, A. Georgiadis, N. Brussee, A. Coorn, H. J. van der Linde, J. Dietderich, F. Alpak, Daniel Eriksen, M. M. MOOIJER‐van den HEUVEL, M. Appel, T. Sorop, O. B. Wilson, S. Berg
When oil fields fall during their lifetime below the bubble point gas comes out of solution. The key questions are at which saturation the gas becomes mobile (“critical gas saturation”) and what the gas mobility is, because mobile gas reduces the production of oil significantly. The traditional view is that the gas phase becomes mobile once gas bubbles grow or expand to a size where they connect and form a percolating path. For typical 3D porous media the saturation corresponding to this percolation limit is on the order of 20%. However, significant literature report on gas mobility below lower limits of percolation thresholds i.e. below 0.1%. A direct experimental insight for that is lacking because laboratory measurements are notoriously difficult since the formation of gas bubbles below the bubble point includes thermodynamic and kinetic aspects, and the pressure decline rates achievable in laboratory experiments are orders of magnitude higher than the decline rates in the field. Here we study the nucleation and transport of gas coming out of solution in-situ in 3D rock using X-ray computed micro tomography which allows direct visualization of the nucleation kinetics and connectivity of gas. We use either propane or a propane–decane mixture as model system and conduct pressure depletion in absence of flow finding that – consistent with the literature – observation of the bubble point in the porous medium is decreased and becomes pressure decline rate dependent because of the bubble nucleation kinetics. That occurs in single-component systems and in hydrocarbon mixtures. Pressure depletion in absence of flow results in critical gas saturations between 20 and 30% which is consistent with typical percolation thresholds in 3D porous structures. That does not explain experimentally observed critical gas saturations significantly below 20%. Also, the respective pore level fluid occupancy where pores are filled with either gas or liquid phase but not partially with both as in normal 2-phase immiscible systems rather diminishes connectivity of gas and liquid phases. This observation indicates that likely other mechanisms play a role in establishing gas mobility at saturations significantly below 20%. Experiments under flow conditions, where gas is injected near the bubble point suggest that diffusion may significantly contribute to the transport of gas and may even be the dominant transport mechanism at field relevant flow rates. The consequence of diffusive transport are compositional gradients where locally the composition is such gas nucleation may occur. That would lead to a disconnected but mobile gas distribution ahead of the convective front. Furthermore, diffusive exchange leads to ripening and anti-ripening effects which influences the distribution for which we see evidence in pressure depletion experiments but not so much at low rate gas injection. Respective relative permeability computed from the imaged fluid distributions using a lattice
{"title":"Capillarity and phase-mobility of a hydrocarbon gas–liquid system","authors":"Ying Gao, A. Georgiadis, N. Brussee, A. Coorn, H. J. van der Linde, J. Dietderich, F. Alpak, Daniel Eriksen, M. M. MOOIJER‐van den HEUVEL, M. Appel, T. Sorop, O. B. Wilson, S. Berg","doi":"10.2516/OGST/2021025","DOIUrl":"https://doi.org/10.2516/OGST/2021025","url":null,"abstract":"When oil fields fall during their lifetime below the bubble point gas comes out of solution. The key questions are at which saturation the gas becomes mobile (“critical gas saturation”) and what the gas mobility is, because mobile gas reduces the production of oil significantly. The traditional view is that the gas phase becomes mobile once gas bubbles grow or expand to a size where they connect and form a percolating path. For typical 3D porous media the saturation corresponding to this percolation limit is on the order of 20%. However, significant literature report on gas mobility below lower limits of percolation thresholds i.e. below 0.1%. A direct experimental insight for that is lacking because laboratory measurements are notoriously difficult since the formation of gas bubbles below the bubble point includes thermodynamic and kinetic aspects, and the pressure decline rates achievable in laboratory experiments are orders of magnitude higher than the decline rates in the field. Here we study the nucleation and transport of gas coming out of solution in-situ in 3D rock using X-ray computed micro tomography which allows direct visualization of the nucleation kinetics and connectivity of gas. We use either propane or a propane–decane mixture as model system and conduct pressure depletion in absence of flow finding that – consistent with the literature – observation of the bubble point in the porous medium is decreased and becomes pressure decline rate dependent because of the bubble nucleation kinetics. That occurs in single-component systems and in hydrocarbon mixtures. Pressure depletion in absence of flow results in critical gas saturations between 20 and 30% which is consistent with typical percolation thresholds in 3D porous structures. That does not explain experimentally observed critical gas saturations significantly below 20%. Also, the respective pore level fluid occupancy where pores are filled with either gas or liquid phase but not partially with both as in normal 2-phase immiscible systems rather diminishes connectivity of gas and liquid phases. This observation indicates that likely other mechanisms play a role in establishing gas mobility at saturations significantly below 20%. Experiments under flow conditions, where gas is injected near the bubble point suggest that diffusion may significantly contribute to the transport of gas and may even be the dominant transport mechanism at field relevant flow rates. The consequence of diffusive transport are compositional gradients where locally the composition is such gas nucleation may occur. That would lead to a disconnected but mobile gas distribution ahead of the convective front. Furthermore, diffusive exchange leads to ripening and anti-ripening effects which influences the distribution for which we see evidence in pressure depletion experiments but not so much at low rate gas injection. Respective relative permeability computed from the imaged fluid distributions using a lattice ","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"5 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76408110","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Isaac Iglesias, Mayra Jiménez, A. M. Gallardo, Edward E. Ávila, V. Morera, A. Viloria, Marvin Ricaurte, J. Tafur
In this work, we report the mechanical properties of an alternative material based on a mixture of natural clay and ferruginous sand in pellet form for CO2 capture. These raw materials were collected from Ecuador, and they contain iron and titanium oxides from volcanic origin. To evaluate the effect of the sand content on the mechanical properties of pellets, the samples were manually prepared with 0 (control sample), 15, and 25 wt.% sand contents and analyzed using free-fall drop impact and uniaxial compression tests. The uniaxial compression test was carried out under three conditions: using sieved sand, using sand without sieving, and under wet conditions. The sand contents caused the drop number to decrease in the free-fall drop impact test. From the uniaxial compression test, the compressive strength, elastic modulus, and toughness were calculated. The elastic modulus showed a better performance for samples with lower porosity. The compressive strength demonstrated higher values for samples with 15 wt.% sand contents than for samples with the other sand contents. The toughness values did not significantly change. It was evidenced that the porosity, mineral composition, and humidity exerted an influence during the mechanical tests. The mineral phases were analyzed by X-ray diffraction, and quantitative analysis based on whole-powder-pattern fitting revealed that the iron and titanium oxide contents increased as the concentration of sand in the pellets increased.
{"title":"Mechanical properties and X-ray diffraction analyses of clay/sand pellets for CO2 adsorption: the effects of sand content and humidity","authors":"Isaac Iglesias, Mayra Jiménez, A. M. Gallardo, Edward E. Ávila, V. Morera, A. Viloria, Marvin Ricaurte, J. Tafur","doi":"10.2516/ogst/2021030","DOIUrl":"https://doi.org/10.2516/ogst/2021030","url":null,"abstract":"In this work, we report the mechanical properties of an alternative material based on a mixture of natural clay and ferruginous sand in pellet form for CO2 capture. These raw materials were collected from Ecuador, and they contain iron and titanium oxides from volcanic origin. To evaluate the effect of the sand content on the mechanical properties of pellets, the samples were manually prepared with 0 (control sample), 15, and 25 wt.% sand contents and analyzed using free-fall drop impact and uniaxial compression tests. The uniaxial compression test was carried out under three conditions: using sieved sand, using sand without sieving, and under wet conditions. The sand contents caused the drop number to decrease in the free-fall drop impact test. From the uniaxial compression test, the compressive strength, elastic modulus, and toughness were calculated. The elastic modulus showed a better performance for samples with lower porosity. The compressive strength demonstrated higher values for samples with 15 wt.% sand contents than for samples with the other sand contents. The toughness values did not significantly change. It was evidenced that the porosity, mineral composition, and humidity exerted an influence during the mechanical tests. The mineral phases were analyzed by X-ray diffraction, and quantitative analysis based on whole-powder-pattern fitting revealed that the iron and titanium oxide contents increased as the concentration of sand in the pellets increased.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"32 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82824698","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Visualizing fluid flow in porous media can provide a better understanding of transport phenomena at the pore scale. In this regard, transparent micromodels are suitable tools to investigate fluid flow in porous media. However, using glass as the primary material makes them inappropriate for predicting the natural behavior of rocks. Moreover, constructing these micromodels is time-consuming via conventional methods. Thus, an alternative approach can be to employ 3D printing technology to fabricate representative porous media. This study investigates fluid flow processes through a transparent microfluidic device based on a complex porous geometry (natural rock) using digital-light processing printing technology. Unlike previous studies, this one has focused on manufacturing repeatability. This micromodel, like a custom-built transparent cell, is capable of modeling single and multiphase transport phenomena. First, the tomographic data of a carbonate rock sample is segmented and 3D printed by a digital-light processing printer. Two miscible and immiscible tracer injection experiments are performed on the printed microfluidic media, while the experiments are verified with the same boundary conditions using a CFD simulator. The comparison of the results is based on Structural Similarity Index Measure (SSIM), where in both miscible and immiscible experiments, more than 80% SSIM is achieved. This confirms the reliability of printing methodology for manufacturing reusable microfluidic models as a promising and reliable tool for visual investigation of fluid flow in porous media. Ultimately, this study presents a novel comprehensive framework for manufacturing 2.5D realistic microfluidic devices (micromodels) from pore-scale rock images that are validated through CFD simulations.
{"title":"Evaluation of 3D printed microfluidic networks to study fluid flow in rocks","authors":"S. M. Mousavi, S. Sadeghnejad, M. Ostadhassan","doi":"10.2516/ogst/2021029","DOIUrl":"https://doi.org/10.2516/ogst/2021029","url":null,"abstract":"Visualizing fluid flow in porous media can provide a better understanding of transport phenomena at the pore scale. In this regard, transparent micromodels are suitable tools to investigate fluid flow in porous media. However, using glass as the primary material makes them inappropriate for predicting the natural behavior of rocks. Moreover, constructing these micromodels is time-consuming via conventional methods. Thus, an alternative approach can be to employ 3D printing technology to fabricate representative porous media. This study investigates fluid flow processes through a transparent microfluidic device based on a complex porous geometry (natural rock) using digital-light processing printing technology. Unlike previous studies, this one has focused on manufacturing repeatability. This micromodel, like a custom-built transparent cell, is capable of modeling single and multiphase transport phenomena. First, the tomographic data of a carbonate rock sample is segmented and 3D printed by a digital-light processing printer. Two miscible and immiscible tracer injection experiments are performed on the printed microfluidic media, while the experiments are verified with the same boundary conditions using a CFD simulator. The comparison of the results is based on Structural Similarity Index Measure (SSIM), where in both miscible and immiscible experiments, more than 80% SSIM is achieved. This confirms the reliability of printing methodology for manufacturing reusable microfluidic models as a promising and reliable tool for visual investigation of fluid flow in porous media. Ultimately, this study presents a novel comprehensive framework for manufacturing 2.5D realistic microfluidic devices (micromodels) from pore-scale rock images that are validated through CFD simulations.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"9 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83132286","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Azad, A. Kamkar-Rouhani, B. Tokhmechi, M. Arashi
In this paper, two methods of kernel bandwidth and wavelet transform are used for simultaneous upscaling of two features of hydrocarbon reservoir. In the bandwidth method, the criterion for upscaling is the cell variability, and by calculating the optimal bandwidth and determining the distance matrix, the upscaling process is performed in a completely non-uniform and unregularly manner. In areas with extreme variability, the bandwidth is considered small enough to maintain the fine scale characteristics of model. Conversely in homogenous areas, with the choice of large bandwidth, the maximum rate of upscaling will occur. The bandwidth upscaling algorithm is an iterative and hierarchical algorithm. The bandwidth method, unlike conventional scale-up methods, focuses on how to upgrid cells and, by determining the optimal averaging window, we will have the least loss information for the fine scale model. Upscaling is a pre-processing to building a simulator model with lower cell number, and thus, reducing volume and computational cost, while maintaining and retaining the basic information of the fine model. Due to the various variability of the reservoir features, the attribute upscaling pattern differs, and in order to show the variability of two features in the upscaling model simultaneously, it is suggested in this paper to upscale two features simultaneously. For simultaneous upscaling, we applied two different approaches; minimum and maximum bandwidth. Moreover, wavelet transformation is applied to upscaling the model. Then, as a result, the variance of the scale-up models based on wavelet is about one-third of the variance of the bandwidth method. Simulation results show that the bandwidth method is a good approach for upscaling the heterogeneous reservoirs.
{"title":"Hierarchical simultaneous upscaling of porosity and permeability features using the bandwidth of kernel function and wavelet transformation in two dimensions: Application to the SPE-10 model","authors":"M. Azad, A. Kamkar-Rouhani, B. Tokhmechi, M. Arashi","doi":"10.2516/OGST/2021006","DOIUrl":"https://doi.org/10.2516/OGST/2021006","url":null,"abstract":"In this paper, two methods of kernel bandwidth and wavelet transform are used for simultaneous upscaling of two features of hydrocarbon reservoir. In the bandwidth method, the criterion for upscaling is the cell variability, and by calculating the optimal bandwidth and determining the distance matrix, the upscaling process is performed in a completely non-uniform and unregularly manner. In areas with extreme variability, the bandwidth is considered small enough to maintain the fine scale characteristics of model. Conversely in homogenous areas, with the choice of large bandwidth, the maximum rate of upscaling will occur. The bandwidth upscaling algorithm is an iterative and hierarchical algorithm. The bandwidth method, unlike conventional scale-up methods, focuses on how to upgrid cells and, by determining the optimal averaging window, we will have the least loss information for the fine scale model. Upscaling is a pre-processing to building a simulator model with lower cell number, and thus, reducing volume and computational cost, while maintaining and retaining the basic information of the fine model. Due to the various variability of the reservoir features, the attribute upscaling pattern differs, and in order to show the variability of two features in the upscaling model simultaneously, it is suggested in this paper to upscale two features simultaneously. For simultaneous upscaling, we applied two different approaches; minimum and maximum bandwidth. Moreover, wavelet transformation is applied to upscaling the model. Then, as a result, the variance of the scale-up models based on wavelet is about one-third of the variance of the bandwidth method. Simulation results show that the bandwidth method is a good approach for upscaling the heterogeneous reservoirs.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"101 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85909045","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
David C. Santos, Marina N. Lamim, D. S. Costa, A. Mehl, P. Couto, M. Paredes
In this study, highly accurate measurements of density and dynamic viscosities of a recombined live oil and its mixture with additional CO2 were performed. The experiments were carried out under pressure and temperature gradients found in Brazilian Pre-salt reservoirs, that is, in the pressure range from (27.6 to 68.9) MPa and at (333.15 and 353.15) K. The assumption of volume change on mixing is evaluated from the experimental results, and the influence of pressure and temperature on the volume change upon mixing is assessed. The densities of mixtures are calculated considering (i) the excess volume approach, and (ii) no volume change. The densities are better correlated using the excess volume approach with Average Absolute Deviations (AAD) of 0.03%. Thirteen mixing rules of viscosity are examined by comparing the predicted values with the experimental viscosity of the recombined live oil + CO2 mixture. The performance of some rules using compositional fractions (molar, volume and weight) is also evaluated. Thus, a total of 28 different ways to calculate the mixture viscosities were tested in this study. The worst result was obtained with Bingham’s method, leading to 148.6% AAD. The best result was obtained from Lederer’s method with 2% AAD and a maximum deviation of 5.8% using volume fractions and the fitting parameter α. In addition, deviations presented by the predictive methods of Chevron, Double log, and Kendall did not exceed 9% AAD, using weight fractions (Chevron and Double log) and molar fractions (Kendall and Monroe).
{"title":"Experimental and modeling studies of density and viscosity behavior of a live fluid due to CO2 injection at reservoir condition","authors":"David C. Santos, Marina N. Lamim, D. S. Costa, A. Mehl, P. Couto, M. Paredes","doi":"10.2516/ogst/2021026","DOIUrl":"https://doi.org/10.2516/ogst/2021026","url":null,"abstract":"In this study, highly accurate measurements of density and dynamic viscosities of a recombined live oil and its mixture with additional CO2 were performed. The experiments were carried out under pressure and temperature gradients found in Brazilian Pre-salt reservoirs, that is, in the pressure range from (27.6 to 68.9) MPa and at (333.15 and 353.15) K. The assumption of volume change on mixing is evaluated from the experimental results, and the influence of pressure and temperature on the volume change upon mixing is assessed. The densities of mixtures are calculated considering (i) the excess volume approach, and (ii) no volume change. The densities are better correlated using the excess volume approach with Average Absolute Deviations (AAD) of 0.03%. Thirteen mixing rules of viscosity are examined by comparing the predicted values with the experimental viscosity of the recombined live oil + CO2 mixture. The performance of some rules using compositional fractions (molar, volume and weight) is also evaluated. Thus, a total of 28 different ways to calculate the mixture viscosities were tested in this study. The worst result was obtained with Bingham’s method, leading to 148.6% AAD. The best result was obtained from Lederer’s method with 2% AAD and a maximum deviation of 5.8% using volume fractions and the fitting parameter α. In addition, deviations presented by the predictive methods of Chevron, Double log, and Kendall did not exceed 9% AAD, using weight fractions (Chevron and Double log) and molar fractions (Kendall and Monroe).","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"70 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85978633","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mohammad Mahdi Moshir Farahi, Mohammad Ahmadi, B. Dabir
Optimization of the water-flooding process in the oilfields is inherently subject to several uncertainties arising from the imperfect reservoir subsurface model and inadequate data. On the other hand, the uncertainty of economic conditions due to oil price fluctuations puts the decision-making process at risk. It is essential to handle optimization problems under both geological and economic uncertainties. In this study, a Pareto-based Multi-Objective Particle Swarm Optimization (MOPSO) method has been utilized to maximize the short-term and long-term production goals, robust to uncertainties. Some modifications, including applying a variable in the procedure of leader determination, namely crowding distance, a corrected archive controller, and a changing boundary exploration, are performed on the MOPSO algorithm. These corrections led to a complete Pareto front with enough diversity on the investigated model, covering the entire solution space. Net Present Value (NPV) is considered the first goal that represents the long-term gains, while a highly discounted NPV (with a discount rate of 25%) has been considered short-term gains since economic uncertainty risk grows with time. The proposed optimization method has been used to optimize water flooding on the Egg benchmark model. Geological uncertainty is represented with ensembles, including 100 model realizations. The k-means clustering method is utilized to reduce the realizations to 10 to reduce the computing cost. The Pareto front is obtained from Robust Optimization (RO) by maximizing average NPV over the ensembles, as the conservative production plan. Results show that optimization over the ensemble of a reduced number of realizations by the k-means technique is consistent with all realizations’ ensembles results, comparing their cumulative density functions. Furthermore, 10 oil price functions have been considered to form the economic uncertainty space. When SNPV and LNPV are optimized, considering uncertainty in oil price scenarios, the Pareto front’s production scenarios are robust to oil price fluctuations. Using the robust Pareto front of LNPV versus SNPV in both cases, one can optimize production strategy conservatively and update it according to the current reservoir and economic conditions. This approach can help a decision-maker to handle unexpected situations in reservoir management.
{"title":"Model-based production optimization under geological and economic uncertainties using multi-objective particle swarm method","authors":"Mohammad Mahdi Moshir Farahi, Mohammad Ahmadi, B. Dabir","doi":"10.2516/ogst/2021039","DOIUrl":"https://doi.org/10.2516/ogst/2021039","url":null,"abstract":"Optimization of the water-flooding process in the oilfields is inherently subject to several uncertainties arising from the imperfect reservoir subsurface model and inadequate data. On the other hand, the uncertainty of economic conditions due to oil price fluctuations puts the decision-making process at risk. It is essential to handle optimization problems under both geological and economic uncertainties. In this study, a Pareto-based Multi-Objective Particle Swarm Optimization (MOPSO) method has been utilized to maximize the short-term and long-term production goals, robust to uncertainties. Some modifications, including applying a variable in the procedure of leader determination, namely crowding distance, a corrected archive controller, and a changing boundary exploration, are performed on the MOPSO algorithm. These corrections led to a complete Pareto front with enough diversity on the investigated model, covering the entire solution space. Net Present Value (NPV) is considered the first goal that represents the long-term gains, while a highly discounted NPV (with a discount rate of 25%) has been considered short-term gains since economic uncertainty risk grows with time. The proposed optimization method has been used to optimize water flooding on the Egg benchmark model. Geological uncertainty is represented with ensembles, including 100 model realizations. The k-means clustering method is utilized to reduce the realizations to 10 to reduce the computing cost. The Pareto front is obtained from Robust Optimization (RO) by maximizing average NPV over the ensembles, as the conservative production plan. Results show that optimization over the ensemble of a reduced number of realizations by the k-means technique is consistent with all realizations’ ensembles results, comparing their cumulative density functions. Furthermore, 10 oil price functions have been considered to form the economic uncertainty space. When SNPV and LNPV are optimized, considering uncertainty in oil price scenarios, the Pareto front’s production scenarios are robust to oil price fluctuations. Using the robust Pareto front of LNPV versus SNPV in both cases, one can optimize production strategy conservatively and update it according to the current reservoir and economic conditions. This approach can help a decision-maker to handle unexpected situations in reservoir management.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"17 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86498766","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Drilling fluid loss always occurs in fracture-porosity reservoirs and it causes severe problems. To reduce and prevent lost circulation, it is important to get to know the cause and the characteristic of drilling fluid loss. According to the approach in the reservoir simulation and well test analysis, a new model for drilling fluid loss in fracture-porosity reservoir is presented. Multi fractures in the formation and drilling fluid seepage between fracture and rock matrix have been considered in the model. The governing equations are derived based on the principle of conservation of mass. The model is solved numerically using Newton-Raphson iterative method. The obtained results indicate that drilling fluid leak-off has great influence on the total leakage volume. It is necessary to consider the impact of the drilling fluid leak-off. In addition, influence of formation properties, such as fracture stiffness, rock matrix porosity, rock matrix permeability, and operation factors, such as pressure difference between wellbore and formation, are also analysed in detail in the paper which could help better understand the factors that influence the drilling fluid loss during drilling operation.
{"title":"A new model for predicting fluid loss in fracture-porosity reservoir","authors":"Liu Jinjiang, Fuxin Zhang, Peng Qian, Wenlin Wu","doi":"10.2516/OGST/2021012","DOIUrl":"https://doi.org/10.2516/OGST/2021012","url":null,"abstract":"Drilling fluid loss always occurs in fracture-porosity reservoirs and it causes severe problems. To reduce and prevent lost circulation, it is important to get to know the cause and the characteristic of drilling fluid loss. According to the approach in the reservoir simulation and well test analysis, a new model for drilling fluid loss in fracture-porosity reservoir is presented. Multi fractures in the formation and drilling fluid seepage between fracture and rock matrix have been considered in the model. The governing equations are derived based on the principle of conservation of mass. The model is solved numerically using Newton-Raphson iterative method. The obtained results indicate that drilling fluid leak-off has great influence on the total leakage volume. It is necessary to consider the impact of the drilling fluid leak-off. In addition, influence of formation properties, such as fracture stiffness, rock matrix porosity, rock matrix permeability, and operation factors, such as pressure difference between wellbore and formation, are also analysed in detail in the paper which could help better understand the factors that influence the drilling fluid loss during drilling operation.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"2 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75662017","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shuyu Sun, M. Edwards, F. Frank, Jingfa Li, A. Salama, Bo Yu
Division of Physical Science and Engineering, King Abdullah University of Science and Technology, Mail box # 2077, Thuwal 23955-6900, Saudi Arabia Chair in Engineering, Swansea University, Singleton Park, Swansea, Wales SA2 8PP, UK Applied Mathematics (Modeling and Numerics), Friedrich-Alexander-University of Erlangen-Nürnberg, Cauerstraße 11, 91058 Erlangen, Germany 4 School of Mechanical Engineering, Beijing Institute of Petrochemical Technology, Beijing 102617, China 5 Faculty of Engineering, University of Regina, Regina, Saskatchewan, S4S 0A2, Canada 6 School of Mechanical Engineering, Beijing Institute of Petrochemical Technology, Beijing 102617, China
{"title":"Editorial: Advanced modeling and simulation of flow in subsurface reservoirs with fractures and wells for a sustainable industry","authors":"Shuyu Sun, M. Edwards, F. Frank, Jingfa Li, A. Salama, Bo Yu","doi":"10.2516/OGST/2021008","DOIUrl":"https://doi.org/10.2516/OGST/2021008","url":null,"abstract":"Division of Physical Science and Engineering, King Abdullah University of Science and Technology, Mail box # 2077, Thuwal 23955-6900, Saudi Arabia Chair in Engineering, Swansea University, Singleton Park, Swansea, Wales SA2 8PP, UK Applied Mathematics (Modeling and Numerics), Friedrich-Alexander-University of Erlangen-Nürnberg, Cauerstraße 11, 91058 Erlangen, Germany 4 School of Mechanical Engineering, Beijing Institute of Petrochemical Technology, Beijing 102617, China 5 Faculty of Engineering, University of Regina, Regina, Saskatchewan, S4S 0A2, Canada 6 School of Mechanical Engineering, Beijing Institute of Petrochemical Technology, Beijing 102617, China","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"395 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78037789","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The 3D reconstruction of the pore space in Opalinus Clay is faced with the difficulty that high-resolution imaging methods reach their limits at the nanometer-sized pores in this material. Until now it has not been possible to image the whole pore space with pore sizes that span two orders of magnitude. Therefore, it has not been possible to predict the transport properties of this material with the help computer simulations that require 3D pore structures as input. Following the concept of self-similarity, a digital pore microstructure was constructed from a real but incomplete pore microstructure. The constructed pore structure has the same pore size spectrum as measured in the laboratory. Computer simulations were used to predict capillary pressure curves during drainage, which also agree with laboratory data. It is predicted, that two-phase transport properties such as the evolution of effective permeability as well as capillary pressures during drainage depend both on transport directions, which should be considered for Opalinus Clay when assessing its suitability as host rock for nuclear waste. This directional dependence is controlled on the pore scale by a geometric anisotropy in the pore space.
{"title":"3D pore microstructures and computer simulation: Effective permeabilities and capillary pressure during drainage in Opalinus Clay","authors":"L. Keller","doi":"10.2516/ogst/2021027","DOIUrl":"https://doi.org/10.2516/ogst/2021027","url":null,"abstract":"The 3D reconstruction of the pore space in Opalinus Clay is faced with the difficulty that high-resolution imaging methods reach their limits at the nanometer-sized pores in this material. Until now it has not been possible to image the whole pore space with pore sizes that span two orders of magnitude. Therefore, it has not been possible to predict the transport properties of this material with the help computer simulations that require 3D pore structures as input. Following the concept of self-similarity, a digital pore microstructure was constructed from a real but incomplete pore microstructure. The constructed pore structure has the same pore size spectrum as measured in the laboratory. Computer simulations were used to predict capillary pressure curves during drainage, which also agree with laboratory data. It is predicted, that two-phase transport properties such as the evolution of effective permeability as well as capillary pressures during drainage depend both on transport directions, which should be considered for Opalinus Clay when assessing its suitability as host rock for nuclear waste. This directional dependence is controlled on the pore scale by a geometric anisotropy in the pore space.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"14 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78536338","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Gas sweetening is one of the important purification processes which is employed to remove acidic contaminants from natural gases prior to meet transport requirements and sale gas specifications. In this work, simulation and parametric studies of the natural gas processing plant of Missan Oil Company/Buzurgan Oil Field of Natural Gas Processing Plant (in Iraq) were considered. After simulation and validation of this plant, the effect of feed temperature and flow rate and solvent concentration were considered. Results show with increasing the feed temperature and flow rate, the amount of H2S and CO2 in the sweet gas stream increases. Then, in the next step, the effect of mixture solvents was studied. Sulfolane–MDEA and MDEA–MEA were selected as a physical–chemical mixture solvent and chemical mixture solvent, respectively. The simulation results show that the solvent price and reboiler duty and cooling duty can be reduced by using a mixture solvent. However, the amount of H2S and CO2 in the sweet gas can be affected by these solvents. The system by a chemical mixture solvent can better performance than other solvents.
{"title":"Simulation and parametric analysis of natural gas sweetening process: a case study of Missan Oil Field in Iraq","authors":"Jassim Mohammed Khanjar, E. Amiri","doi":"10.2516/ogst/2021033","DOIUrl":"https://doi.org/10.2516/ogst/2021033","url":null,"abstract":"Gas sweetening is one of the important purification processes which is employed to remove acidic contaminants from natural gases prior to meet transport requirements and sale gas specifications. In this work, simulation and parametric studies of the natural gas processing plant of Missan Oil Company/Buzurgan Oil Field of Natural Gas Processing Plant (in Iraq) were considered. After simulation and validation of this plant, the effect of feed temperature and flow rate and solvent concentration were considered. Results show with increasing the feed temperature and flow rate, the amount of H2S and CO2 in the sweet gas stream increases. Then, in the next step, the effect of mixture solvents was studied. Sulfolane–MDEA and MDEA–MEA were selected as a physical–chemical mixture solvent and chemical mixture solvent, respectively. The simulation results show that the solvent price and reboiler duty and cooling duty can be reduced by using a mixture solvent. However, the amount of H2S and CO2 in the sweet gas can be affected by these solvents. The system by a chemical mixture solvent can better performance than other solvents.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"49 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79895891","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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