N. Dubos‐Sallée, A. Fourno, Jeanneth Zarate-Rada, V. Gervais, P. Rasolofosaon, O. Lerat
In an Enhanced Oil Recovery (EOR) process, one of the main difficulties is to quickly evaluate if the injected chemical products actually improve oil recovery in the reservoir. The efficiency of the process can be monitored in the vicinity of wells, but it may take time to estimate it globally in the reservoir. The objective of this paper is to investigate the ability of 4D seismics to bridge this gap and to help predict the success or breakdown of a production strategy at reservoir scale. To that purpose, we consider a complete workflow for simulating realistic reservoir exploitation using chemical EOR and 4D seismic modeling. This workflow spans from geological description to seismic monitoring simulation and seismic attributes analysis, through geological and reservoir modeling. It is applied here on a realistic case study derived from an outcrop analog of turbiditic reservoirs, for which the efficiency of chemical EOR by polymer and surfactant injection is demonstrated. For this specific field monitoring application, the impact of both waterflooding and proposed EOR injection is visible on the computed seismics. However, EOR injection induces a more continuous water front that can be clearly visible on seismics. In this case, the EOR efficiency can thus be related to the continuity of the water front as seen on seismics. Nevertheless, in other cases, chemical EOR injections may have more moderate impacts, or the field properties may be less adapted to seismic monitoring. This points out the importance of the proposed workflow to check the relevance of seismic monitoring and to design the most adapted monitoring strategy. Numerous perspectives are proposed at the end of the paper. In particular, experts of the different disciplines involved in the proposed workflow can benefit from the availability of a complete set of well-controlled data of various types to test and improve their own tools. In contrast, the non-experts can easily and quickly benefit from “hands-on” experiments for understanding the involved phenomena. Furthermore, the proposed workflow can be directly applied to geological reservoirs all over the world.
{"title":"A complete workflow applied on an oil reservoir analogue to evaluate the ability of 4D seismics to anticipate the success of a chemical enhanced oil recovery process","authors":"N. Dubos‐Sallée, A. Fourno, Jeanneth Zarate-Rada, V. Gervais, P. Rasolofosaon, O. Lerat","doi":"10.2516/ogst/2020011","DOIUrl":"https://doi.org/10.2516/ogst/2020011","url":null,"abstract":"In an Enhanced Oil Recovery (EOR) process, one of the main difficulties is to quickly evaluate if the injected chemical products actually improve oil recovery in the reservoir. The efficiency of the process can be monitored in the vicinity of wells, but it may take time to estimate it globally in the reservoir. The objective of this paper is to investigate the ability of 4D seismics to bridge this gap and to help predict the success or breakdown of a production strategy at reservoir scale. To that purpose, we consider a complete workflow for simulating realistic reservoir exploitation using chemical EOR and 4D seismic modeling. This workflow spans from geological description to seismic monitoring simulation and seismic attributes analysis, through geological and reservoir modeling. It is applied here on a realistic case study derived from an outcrop analog of turbiditic reservoirs, for which the efficiency of chemical EOR by polymer and surfactant injection is demonstrated. For this specific field monitoring application, the impact of both waterflooding and proposed EOR injection is visible on the computed seismics. However, EOR injection induces a more continuous water front that can be clearly visible on seismics. In this case, the EOR efficiency can thus be related to the continuity of the water front as seen on seismics. Nevertheless, in other cases, chemical EOR injections may have more moderate impacts, or the field properties may be less adapted to seismic monitoring. This points out the importance of the proposed workflow to check the relevance of seismic monitoring and to design the most adapted monitoring strategy. Numerous perspectives are proposed at the end of the paper. In particular, experts of the different disciplines involved in the proposed workflow can benefit from the availability of a complete set of well-controlled data of various types to test and improve their own tools. In contrast, the non-experts can easily and quickly benefit from “hands-on” experiments for understanding the involved phenomena. Furthermore, the proposed workflow can be directly applied to geological reservoirs all over the world.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84222008","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}
During the past decade, researchers have used different Nano-Particles (NPs) due to their unique characteristics for improving formulation of Oil-Based Drilling Fluids (OBDFs). This study is the first research that investigates the effect of a Modified Nano Clay (MNC), namely CLOISITE 5 and non-functionalized Nano Graphene (NG) on rheology, electrical/emulsion stability, and filtration control ability, as the main properties of OBDFs. Initially, five concentrations of both NPs (0.25, 0.5, 1, 1.5, and 2 wt%) were added separately into an NP-free OBDF (the base fluid). Then, rheological properties and electrical stability of all prepared fluids were measured at three 90, 140, and 180 °F temperatures. Moreover, filtration test was carried out under 500 psi (3447 kPa) differential pressure and exposed to 300 °F temperature for all fluids. Since experimentally measured shear stresses followed well both Herschel Bulkley (shear-thinning) and Bingham Plastic models, effects of temperature and the NPs concentration on both model parameters are investigated more deeply in the paper. Activation energies calculated from Arrhenius model showed that MNC is more effective than NG on reducing the dependency of apparent and plastic viscosities of the base fluid on temperature. MNC, due to its amphiphilic structure, significantly stabilizes water-in-oil emulsion at all temperatures and concentrations, but NG with high electrical conductivity reduces the emulsion stability. The nanofluids containing 0.5 wt% MNC and 0.25 wt% NG which have respectively 32.6% and 43.5% fewer filtrate volumes than the base fluid, were considered as the optimal nanofluids from controlling filtration into formation aspect. Finally, MNC is applicable to enhance the formulation of the OBDF through supporting its commercial viscosifier, emulsifiers, and fluid loss control agent, but the negative effect of NG on emulsion stability limits its application.
{"title":"Effect of a modified nano clay and nano graphene on rheology, stability of water-in-oil emulsion, and filtration control ability of oil-based drilling fluids: a comparative experimental approach","authors":"Vahid Nooripoor, A. Hashemi","doi":"10.2516/ogst/2020032","DOIUrl":"https://doi.org/10.2516/ogst/2020032","url":null,"abstract":"During the past decade, researchers have used different Nano-Particles (NPs) due to their unique characteristics for improving formulation of Oil-Based Drilling Fluids (OBDFs). This study is the first research that investigates the effect of a Modified Nano Clay (MNC), namely CLOISITE 5 and non-functionalized Nano Graphene (NG) on rheology, electrical/emulsion stability, and filtration control ability, as the main properties of OBDFs. Initially, five concentrations of both NPs (0.25, 0.5, 1, 1.5, and 2 wt%) were added separately into an NP-free OBDF (the base fluid). Then, rheological properties and electrical stability of all prepared fluids were measured at three 90, 140, and 180 °F temperatures. Moreover, filtration test was carried out under 500 psi (3447 kPa) differential pressure and exposed to 300 °F temperature for all fluids. Since experimentally measured shear stresses followed well both Herschel Bulkley (shear-thinning) and Bingham Plastic models, effects of temperature and the NPs concentration on both model parameters are investigated more deeply in the paper. Activation energies calculated from Arrhenius model showed that MNC is more effective than NG on reducing the dependency of apparent and plastic viscosities of the base fluid on temperature. MNC, due to its amphiphilic structure, significantly stabilizes water-in-oil emulsion at all temperatures and concentrations, but NG with high electrical conductivity reduces the emulsion stability. The nanofluids containing 0.5 wt% MNC and 0.25 wt% NG which have respectively 32.6% and 43.5% fewer filtrate volumes than the base fluid, were considered as the optimal nanofluids from controlling filtration into formation aspect. Finally, MNC is applicable to enhance the formulation of the OBDF through supporting its commercial viscosifier, emulsifiers, and fluid loss control agent, but the negative effect of NG on emulsion stability limits its application.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84981371","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}
Well deliverability reduction as a result of liquid (condensate) build up in near well regions is an important deal in the development of gas condensate reservoirs. The relative permeability is an imperative factor for characterization of the aforementioned problem. The dependence of relative permeability on the coupled effects of Interfacial Tension (IFT) and flow velocity (capillary number) together with phase saturation is well established in the literature. In gas condensate reservoirs, however, the influence of IFT and velocity on this parameter becomes more evident. The current paper aims to establish a new model for predicting the relative permeability of gas condensate reservoirs by employing the direct interpolation technique. To this end, the regression analysis was carried out using seven sets of literature published experimental data. The validity analysis was executed by utilizing statistical parameters integrated with graphical descriptions. Furthermore, a comparison was carried out between the proposed model and some literature published empirical models. The results of the examination demonstrated that the new model outperformed other correlations from the standpoints of accuracy and reliability.
{"title":"A proposed capillary number dependent model for prediction of relative permeability in gas condensate reservoirs: a robust non-linear regression analysis","authors":"Mehdi Mahdaviara, A. Helalizadeh","doi":"10.2516/ogst/2020017","DOIUrl":"https://doi.org/10.2516/ogst/2020017","url":null,"abstract":"Well deliverability reduction as a result of liquid (condensate) build up in near well regions is an important deal in the development of gas condensate reservoirs. The relative permeability is an imperative factor for characterization of the aforementioned problem. The dependence of relative permeability on the coupled effects of Interfacial Tension (IFT) and flow velocity (capillary number) together with phase saturation is well established in the literature. In gas condensate reservoirs, however, the influence of IFT and velocity on this parameter becomes more evident. The current paper aims to establish a new model for predicting the relative permeability of gas condensate reservoirs by employing the direct interpolation technique. To this end, the regression analysis was carried out using seven sets of literature published experimental data. The validity analysis was executed by utilizing statistical parameters integrated with graphical descriptions. Furthermore, a comparison was carried out between the proposed model and some literature published empirical models. The results of the examination demonstrated that the new model outperformed other correlations from the standpoints of accuracy and reliability.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89453328","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}
Hui Liu, Zhangxin Chen, L. Shen, X. Guo, Dongqi Ji
Reservoir simulation is of interdisciplinary research, including petroleum engineering, mathematics, and computer sciences. It studies multi-phase (water, oil and gas) flow in porous media and well modelling. The latter describes well behavior using physical and mathematical methods. In real world applications, there are many types of wells, such as injection wells, production wells and heaters, and their various operations, such as pressure control, rate control and energy control. This paper presents commonly used well types, well operations, and their mathematical models, such as bottom hole pressure, water rate, oil rate, liquid rate, subcool, and steam control. These are the most widely applied models in thermal reservoir simulations, and some of them can even be applied to the black oil and compositional models. The purpose of this paper is to review these well modelling methods and their mathematical models, which explain how the well operations are defined and computed. We believe a detailed introduction is important to other reseachers and simulator developers. They have been implemented in our in-house parallel thermal simulator. Numerical experiments have been carried out to validate the model implementations and demonstrate the scalability of the parallel thermal simulator.
{"title":"Well modelling methods in thermal reservoir simulation","authors":"Hui Liu, Zhangxin Chen, L. Shen, X. Guo, Dongqi Ji","doi":"10.2516/ogst/2020058","DOIUrl":"https://doi.org/10.2516/ogst/2020058","url":null,"abstract":"Reservoir simulation is of interdisciplinary research, including petroleum engineering, mathematics, and computer sciences. It studies multi-phase (water, oil and gas) flow in porous media and well modelling. The latter describes well behavior using physical and mathematical methods. In real world applications, there are many types of wells, such as injection wells, production wells and heaters, and their various operations, such as pressure control, rate control and energy control. This paper presents commonly used well types, well operations, and their mathematical models, such as bottom hole pressure, water rate, oil rate, liquid rate, subcool, and steam control. These are the most widely applied models in thermal reservoir simulations, and some of them can even be applied to the black oil and compositional models. The purpose of this paper is to review these well modelling methods and their mathematical models, which explain how the well operations are defined and computed. We believe a detailed introduction is important to other reseachers and simulator developers. They have been implemented in our in-house parallel thermal simulator. Numerical experiments have been carried out to validate the model implementations and demonstrate the scalability of the parallel thermal simulator.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89971851","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}
Mobilization of crude oil from the subsurface porous media by emulsion injection is one of the Chemical Enhanced Oil Recovery (C-EOR) techniques. However, deterioration of emulsion by phase separation under harsh reservoir conditions like high salinity, acidic or alkaline nature and high temperature pose a challenge for the emulsion to be a successful EOR agent. Present study aims at formulation of Oil-in-Water (O/W) emulsion stabilized by Sodium Dodecyl Sulfate (SDS) using the optimum values of independent variables – salinity, pH and temperature. The influence of above parameters on the physiochemical properties of the emulsion such as average droplet size, zeta (ζ) potential, conductivity and rheological properties were investigated to optimize the properties. The influence of complex interactions of independent variables on emulsion characteristics were premeditated by experimental model obtained by Taguchi Orthogonal Array (TOA) method. Accuracy and significance of the experimental model was verified using Analysis Of Variance (ANOVA). Results indicated that the experimental models were significantly (p < 0.05) fitted with main influence of salinity (making it a critical variable) followed by its interactions with pH and temperature for all the responses studied for the emulsion properties. No significant difference between the predicted and experimental response values of emulsion ensured the adequacy of the experimental model. Formulated optimized emulsion manifested good stability with 2417.73 nm droplet size, −72.52 mV ζ-potential and a stable rheological (viscosity and viscoelastic) behavior at extensive temperature range. Ultralow Interfacial Tension (IFT) value of 2.22E-05 mN/m was obtained at the interface of crude oil and the emulsion. A favorable wettability alteration of rock from intermediate-wet to water-wet was revealed by contact angle measurement and an enhanced emulsification behavior with crude oil by miscibility test. A tertiary recovery of 21.03% of Original Oil In Place (OOIP) was obtained on sandstone core by optimized emulsion injection. Therefore, performance assessment of optimized emulsion under reservoir conditions confirms its capability as an effective oil-displacing agent.
{"title":"Design and formulation of surfactant stabilized O/W emulsion for application in enhanced oil recovery: effect of pH, salinity and temperature","authors":"Narendra Kumar, Saif Ali, Amit Kumar, A. Mandal","doi":"10.2516/ogst/2020066","DOIUrl":"https://doi.org/10.2516/ogst/2020066","url":null,"abstract":"Mobilization of crude oil from the subsurface porous media by emulsion injection is one of the Chemical Enhanced Oil Recovery (C-EOR) techniques. However, deterioration of emulsion by phase separation under harsh reservoir conditions like high salinity, acidic or alkaline nature and high temperature pose a challenge for the emulsion to be a successful EOR agent. Present study aims at formulation of Oil-in-Water (O/W) emulsion stabilized by Sodium Dodecyl Sulfate (SDS) using the optimum values of independent variables – salinity, pH and temperature. The influence of above parameters on the physiochemical properties of the emulsion such as average droplet size, zeta (ζ) potential, conductivity and rheological properties were investigated to optimize the properties. The influence of complex interactions of independent variables on emulsion characteristics were premeditated by experimental model obtained by Taguchi Orthogonal Array (TOA) method. Accuracy and significance of the experimental model was verified using Analysis Of Variance (ANOVA). Results indicated that the experimental models were significantly (p < 0.05) fitted with main influence of salinity (making it a critical variable) followed by its interactions with pH and temperature for all the responses studied for the emulsion properties. No significant difference between the predicted and experimental response values of emulsion ensured the adequacy of the experimental model. Formulated optimized emulsion manifested good stability with 2417.73 nm droplet size, −72.52 mV ζ-potential and a stable rheological (viscosity and viscoelastic) behavior at extensive temperature range. Ultralow Interfacial Tension (IFT) value of 2.22E-05 mN/m was obtained at the interface of crude oil and the emulsion. A favorable wettability alteration of rock from intermediate-wet to water-wet was revealed by contact angle measurement and an enhanced emulsification behavior with crude oil by miscibility test. A tertiary recovery of 21.03% of Original Oil In Place (OOIP) was obtained on sandstone core by optimized emulsion injection. Therefore, performance assessment of optimized emulsion under reservoir conditions confirms its capability as an effective oil-displacing agent.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86559855","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}
In-situemulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4brine. For instance, the injection of MgSO4solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.
{"title":"Experimental study ofin-situW/O emulsification during the injection of MgSO4and Na2CO3solutions in a glass micromodel","authors":"S. Palizdan, H. Doryani, M. Riazi, M. Malayeri","doi":"10.2516/ogst/2020072","DOIUrl":"https://doi.org/10.2516/ogst/2020072","url":null,"abstract":"In-situemulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4brine. For instance, the injection of MgSO4solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76460808","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}
Fulin Wang, T. Yang, Yun-fei Zhao, Yanjun Fang, Fulin Wang, Gaojun Shan, Guangsheng Cao
Asphalt profile control is an effective method, which can further improve oil recovery of reservoir polymer flooded, it has a lot of advantages including high strength profile control, seal strata formation efficiency, low cost and no pollution, but there has not a perfect evaluation system for its development mode. The effect of different concentration, injection rate, radius of profile control, the timing of profile and segment combination way on the oil displacement effect of the asphalt profile control were researched using numerical simulation method on actual typical well area in Daqing oilfield, and the mechanism of asphalt profile control was studied in detail. According to the results of laboratory test, the largest Enhanced Oil Recovery (EOR) of asphalt was obtained at injection concentration 4000 mg/L, and the best combination was “high–low–high” concentration slug mode. According to the results of numerical simulation, the best concentration, injection rate, radius of profile control and injection timing were 4000 mg/L, 0.15 PV/a (Pore Volume [PV], m3), 1/2 of well spacing and 96% water cut in single slug of asphalt injection system, when the injection condition was multiple slug, the “high–low–high” slug combination mode was the best injection mode. These results could provide effective development basis for asphalt profile control after polymer flooding in thick oil layers.
{"title":"Optimization of development mode of asphalt profile control based on numerical simulation and study of its mechanism","authors":"Fulin Wang, T. Yang, Yun-fei Zhao, Yanjun Fang, Fulin Wang, Gaojun Shan, Guangsheng Cao","doi":"10.2516/ogst/2020020","DOIUrl":"https://doi.org/10.2516/ogst/2020020","url":null,"abstract":"Asphalt profile control is an effective method, which can further improve oil recovery of reservoir polymer flooded, it has a lot of advantages including high strength profile control, seal strata formation efficiency, low cost and no pollution, but there has not a perfect evaluation system for its development mode. The effect of different concentration, injection rate, radius of profile control, the timing of profile and segment combination way on the oil displacement effect of the asphalt profile control were researched using numerical simulation method on actual typical well area in Daqing oilfield, and the mechanism of asphalt profile control was studied in detail. According to the results of laboratory test, the largest Enhanced Oil Recovery (EOR) of asphalt was obtained at injection concentration 4000 mg/L, and the best combination was “high–low–high” concentration slug mode. According to the results of numerical simulation, the best concentration, injection rate, radius of profile control and injection timing were 4000 mg/L, 0.15 PV/a (Pore Volume [PV], m3), 1/2 of well spacing and 96% water cut in single slug of asphalt injection system, when the injection condition was multiple slug, the “high–low–high” slug combination mode was the best injection mode. These results could provide effective development basis for asphalt profile control after polymer flooding in thick oil layers.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89208217","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 detailed geological fine grids are upscaled to create reliably sized simulation coarse models to solve flow equations in a more efficient way. Any upscaling process results in a loss of accuracy, along with an increase of errors. Numerical dispersion, heterogeneity loss, and connectivity misrepresentation are responsible for the upscaling errors. Recognizing the source of each error, and the behavior of influential factors through upscaling process could provide an optimum level of upscaling and an evaluation of upscaling methods’ accuracy. Despite the importance of upscaling error, little attention has been paid to this subject. This paper represents a rigorous analysis of the heterogeneity loss behavior associated with the relative permeability contrast and the mobility ratio under a waterflooding process. For this purpose, heterogeneous fine grid models are constructed by the fractional Brownian motion process. The models are upscaled by three upscaling factors. The models achieved are implemented to eliminate the impact of numerical error among upscaling errors in order to focus strictly on heterogeneity loss. Water–oil displacement simulation is then performed on fine and corresponding refined upscaled models at three different ratios of relative permeabilities and mobility ratios. In the next stage, the relation between flow performance error and heterogeneity loss is investigated by the heterogeneity loss plot. The slope of this plot provides the reservoir engineer an insight to evaluate the performance of upscaling methods and the behavior of the influential factors on upscaling errors. Moreover, by using the heterogeneity loss plot for each ratio, a limit of coarsening is presented. Based on the results, the heterogeneity loss error is affected more by the mobility ratio contrast than the relative permeability difference. Also, it is demonstrated that water-wet reservoirs with light oil are more sensitive to the level of upscaling.
{"title":"Analysis of the impacts of relative permeability and mobility ratio on heterogeneity loss error during upscaling of geological models","authors":"A. Darban, M. Ghaedi, J. Qajar","doi":"10.2516/ogst/2020049","DOIUrl":"https://doi.org/10.2516/ogst/2020049","url":null,"abstract":"The detailed geological fine grids are upscaled to create reliably sized simulation coarse models to solve flow equations in a more efficient way. Any upscaling process results in a loss of accuracy, along with an increase of errors. Numerical dispersion, heterogeneity loss, and connectivity misrepresentation are responsible for the upscaling errors. Recognizing the source of each error, and the behavior of influential factors through upscaling process could provide an optimum level of upscaling and an evaluation of upscaling methods’ accuracy. Despite the importance of upscaling error, little attention has been paid to this subject. This paper represents a rigorous analysis of the heterogeneity loss behavior associated with the relative permeability contrast and the mobility ratio under a waterflooding process. For this purpose, heterogeneous fine grid models are constructed by the fractional Brownian motion process. The models are upscaled by three upscaling factors. The models achieved are implemented to eliminate the impact of numerical error among upscaling errors in order to focus strictly on heterogeneity loss. Water–oil displacement simulation is then performed on fine and corresponding refined upscaled models at three different ratios of relative permeabilities and mobility ratios. In the next stage, the relation between flow performance error and heterogeneity loss is investigated by the heterogeneity loss plot. The slope of this plot provides the reservoir engineer an insight to evaluate the performance of upscaling methods and the behavior of the influential factors on upscaling errors. Moreover, by using the heterogeneity loss plot for each ratio, a limit of coarsening is presented. Based on the results, the heterogeneity loss error is affected more by the mobility ratio contrast than the relative permeability difference. Also, it is demonstrated that water-wet reservoirs with light oil are more sensitive to the level of upscaling.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86198920","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 spatiotemporal evolution of transients in fractured rocks often displays unusual characteristics and is traced to multifaceted origins such as micro-discontinuity in rock properties, rock fragmentation, long-range connectivity and complex flow paths. A physics-based model that incorporates transient propagation wherein the mean square displacement of the diffusion front follows a nonlinear scaling with time is proposed. This model is based on fractional diffusion. The motivation for fractional flux laws follows from the existence of long-range connectivity that results in the mean square displacement of fronts moving faster than predicted by classical models; correspondingly, obstructions and discontinuities, local flow reversals, intercalations, etc. produce the opposite effect with fronts moving at a slower rate than classical predictions. The interplay of these two competing behaviors is quantified. We simulate transient production in a porous rock at the Theis scale as a result of production through a horizontal well consisting of multiple hydraulic fractures. Asymptotic solutions are derived and computations verified. The practical potential of this model is described through an example and the movement of fronts under the constraints of this model is demonstrated through the new expressions developed in this work. We demonstrate that this model offers a potential avenue to explain other behaviors noted in the literature. Though this work is developed in the context of applications to the earth sciences (production of hydrocarbons, extraction of geothermal resources, sequestration of radioactive waste and other fluids, groundwater flow), a minimal change in the Nomenclature permits application to other contexts. Ideas proposed here are particularly useful in the context of superdiffusion in bounded systems which until now, in many ways, has been considered to be an open problem.
{"title":"A study in fractional diffusion: Fractured rocks produced through horizontal wells with multiple, hydraulic fractures","authors":"R. Raghavan, Chih-Cheng Chen","doi":"10.2516/ogst/2020062","DOIUrl":"https://doi.org/10.2516/ogst/2020062","url":null,"abstract":"The spatiotemporal evolution of transients in fractured rocks often displays unusual characteristics and is traced to multifaceted origins such as micro-discontinuity in rock properties, rock fragmentation, long-range connectivity and complex flow paths. A physics-based model that incorporates transient propagation wherein the mean square displacement of the diffusion front follows a nonlinear scaling with time is proposed. This model is based on fractional diffusion. The motivation for fractional flux laws follows from the existence of long-range connectivity that results in the mean square displacement of fronts moving faster than predicted by classical models; correspondingly, obstructions and discontinuities, local flow reversals, intercalations, etc. produce the opposite effect with fronts moving at a slower rate than classical predictions. The interplay of these two competing behaviors is quantified. We simulate transient production in a porous rock at the Theis scale as a result of production through a horizontal well consisting of multiple hydraulic fractures. Asymptotic solutions are derived and computations verified. The practical potential of this model is described through an example and the movement of fronts under the constraints of this model is demonstrated through the new expressions developed in this work. We demonstrate that this model offers a potential avenue to explain other behaviors noted in the literature. Though this work is developed in the context of applications to the earth sciences (production of hydrocarbons, extraction of geothermal resources, sequestration of radioactive waste and other fluids, groundwater flow), a minimal change in the Nomenclature permits application to other contexts. Ideas proposed here are particularly useful in the context of superdiffusion in bounded systems which until now, in many ways, has been considered to be an open problem.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78034408","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}
A predictive simulation model was applied to design a fixed-bed adsorber for studying the removal of Total Organic Acid (TOA) anions from lean Methyldiethanolamine (MDEA) solution using Calcium Alginate Bentonite (CAB) clay hybrid composite adsorbent. Unlike other conventional techniques typically used for packed bed design, the predictive Homogeneous Surface Diffusion Model (HSDM) does not require any test column breakthrough curves a priori. Mass transfer coefficients and isotherm model parameters are provided as input data to HSDM for simulating column breakthrough curves. Various isotherm models were fitted to batch equilibrium data for TOA adsorption on CAB composite adsorbent. Based on Akaike Information Criterion (AIC), Freundlich isotherm was selected and the model parameters were obtained by non-linear regression. Film transfer coefficients and surface diffusivities were determined using appropriate empirical correlations available in the literature. HSDM predictions were first validated using lab-scale column adsorption data generated at lower residence times. The effects of dimensionless numbers (Biot and Stanton) on breakthrough times were investigated using the dimensionless HSDM system and a suitable scale-up regime (Bi& ~& 1 and St& >& 10) was established wherein the sensitivity of mass transfer parameters would be minimal. Using similitude rules on key design parameters, a pilot-scale adsorption column was designed and breakthrough curves were generated using the validated HSDM. The appropriateness of the design technique was verified by comparing the estimated breakthrough data and column design parameters with conventional scale-up and kinetic approaches.
采用预测模拟模型设计固定床吸附装置，研究海藻酸钙膨润土(CAB)粘土杂化复合吸附剂对贫甲基二乙醇胺(MDEA)溶液中总有机酸(TOA)阴离子的去除效果。与填充床设计的其他常规技术不同，预测均匀表面扩散模型(HSDM)不需要任何先验的测试柱突破曲线。将传质系数和等温线模型参数作为HSDM模拟柱突曲线的输入数据。采用不同的等温线模型拟合了CAB复合吸附剂吸附TOA的批量平衡数据。基于赤池信息准则(Akaike Information Criterion, AIC)，选择Freundlich等温线，通过非线性回归得到模型参数。薄膜转移系数和表面扩散系数是用文献中可用的适当的经验相关性来确定的。HSDM预测首先通过较低停留时间产生的实验室规模柱吸附数据进行验证。使用无量纲HSDM系统研究了无量纲数(Biot和Stanton)对突破时间的影响，并建立了一个合适的放大范围(Bi& ~& 1和St& >& 10)，其中传质参数的灵敏度最小。利用关键设计参数的相似规则，设计了中试吸附柱，并利用验证后的HSDM生成了突破曲线。通过将估计的突破数据和柱设计参数与传统的放大和动力学方法进行比较，验证了设计技术的适用性。
{"title":"Design of adsorption column for reclamation of methyldiethanolamine using homogeneous surface diffusion model","authors":"P. Kannan, Priyabrata Pal, F. Banat","doi":"10.2516/ogst/2020073","DOIUrl":"https://doi.org/10.2516/ogst/2020073","url":null,"abstract":"A predictive simulation model was applied to design a fixed-bed adsorber for studying the removal of Total Organic Acid (TOA) anions from lean Methyldiethanolamine (MDEA) solution using Calcium Alginate Bentonite (CAB) clay hybrid composite adsorbent. Unlike other conventional techniques typically used for packed bed design, the predictive Homogeneous Surface Diffusion Model (HSDM) does not require any test column breakthrough curves a priori. Mass transfer coefficients and isotherm model parameters are provided as input data to HSDM for simulating column breakthrough curves. Various isotherm models were fitted to batch equilibrium data for TOA adsorption on CAB composite adsorbent. Based on Akaike Information Criterion (AIC), Freundlich isotherm was selected and the model parameters were obtained by non-linear regression. Film transfer coefficients and surface diffusivities were determined using appropriate empirical correlations available in the literature. HSDM predictions were first validated using lab-scale column adsorption data generated at lower residence times. The effects of dimensionless numbers (Biot and Stanton) on breakthrough times were investigated using the dimensionless HSDM system and a suitable scale-up regime (Bi& ~& 1 and St& >& 10) was established wherein the sensitivity of mass transfer parameters would be minimal. Using similitude rules on key design parameters, a pilot-scale adsorption column was designed and breakthrough curves were generated using the validated HSDM. The appropriateness of the design technique was verified by comparing the estimated breakthrough data and column design parameters with conventional scale-up and kinetic approaches.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":null,"pages":null},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78536212","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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