Stokes flow of a Newtonian fluid through oil and gas production tubing of uniform diameter is studied. Using a direct simulation on computer-aided design of discretised conduits, velocity profiles with gravitational effect and pressure fields are obtained for production tubing of different inner but uniform diameter. The results obtained with this new technique are compared with the integrated form of the Hagen–Poiseuille equation (i.e. , lubrication approximation) and data obtained from experimental and numerical studies for flow in vertical pipes. Good agreement is found in the creeping flow regime between the computed and measured pressure fields with a coefficient of correlation of 0.97. Further, computed velocity field was benchmarked against ANSYS Fluent ; a finite element commercial software package, in a single-phase flow simulation using the axial velocity profile computed at predefined locations along the geometric domains. This method offers an improved solution approach over other existing methods both in terms of computational speed and accuracy.
{"title":"A finite-element algorithm for Stokes flow through oil and gas production tubing of uniform diameter","authors":"Lateef T. Akanji, J. Chidamoio","doi":"10.2516/OGST/2020067","DOIUrl":"https://doi.org/10.2516/OGST/2020067","url":null,"abstract":"Stokes flow of a Newtonian fluid through oil and gas production tubing of uniform diameter is studied. Using a direct simulation on computer-aided design of discretised conduits, velocity profiles with gravitational effect and pressure fields are obtained for production tubing of different inner but uniform diameter. The results obtained with this new technique are compared with the integrated form of the Hagen–Poiseuille equation (i.e. , lubrication approximation) and data obtained from experimental and numerical studies for flow in vertical pipes. Good agreement is found in the creeping flow regime between the computed and measured pressure fields with a coefficient of correlation of 0.97. Further, computed velocity field was benchmarked against ANSYS Fluent ; a finite element commercial software package, in a single-phase flow simulation using the axial velocity profile computed at predefined locations along the geometric domains. This method offers an improved solution approach over other existing methods both in terms of computational speed and accuracy.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"38 1","pages":"79"},"PeriodicalIF":1.5,"publicationDate":"2020-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82264182","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 past decades have witnessed a rapid development of enhanced oil recovery techniques, among which the effect of salinity has become a very attractive topic due to its significant advantages on environmental protection and economical benefits. Numerous studies have been reported focusing on analysis of the mechanisms behind low salinity waterflooding in order to better design the injected salinity under various working conditions and reservoir properties. However, the effect of injection salinity on pipeline scaling has not been widely studied, but this mechanism is important to gathering, transportation and storage for petroleum industry. In this paper, an exhaustive literature review is conducted to summarize several well-recognized and widely accepted mechanisms, including fine migration, wettability alteration, double layer expansion, and multicomponent ion exchange. These mechanisms can be correlated with each other, and certain combined effects may be defined as other mechanisms. In order to mathematically model and numerically describe the fluid behaviors in injection pipelines considering injection salinity, an exploratory phase-field model is presented to simulate the multiphase flow in injection pipeline where scale formation may take place. The effect of injection salinity is represented by the scaling tendency to describe the possibility of scale formation when the scaling species are attached to the scaled structure. It can be easily referred from the simulation result that flow and scaling conditions are significantly affected if a salinity-dependent scaling tendency is considered. Thus, this mechanism should be taken into account in the design of injection process if a sustainable exploitation technique is applied by using purified production water as injection fluid. Finally, remarks and suggestions are provided based on our extensive review and preliminary investigation, to help inspire the future discussions.
{"title":"Effect of salinity on oil production: review on low salinity waterflooding mechanisms and exploratory study on pipeline scaling","authors":"Tao Zhang, Yiteng Li, Chenguang Li, Shuyu Sun","doi":"10.2516/ogst/2020045","DOIUrl":"https://doi.org/10.2516/ogst/2020045","url":null,"abstract":"The past decades have witnessed a rapid development of enhanced oil recovery techniques, among which the effect of salinity has become a very attractive topic due to its significant advantages on environmental protection and economical benefits. Numerous studies have been reported focusing on analysis of the mechanisms behind low salinity waterflooding in order to better design the injected salinity under various working conditions and reservoir properties. However, the effect of injection salinity on pipeline scaling has not been widely studied, but this mechanism is important to gathering, transportation and storage for petroleum industry. In this paper, an exhaustive literature review is conducted to summarize several well-recognized and widely accepted mechanisms, including fine migration, wettability alteration, double layer expansion, and multicomponent ion exchange. These mechanisms can be correlated with each other, and certain combined effects may be defined as other mechanisms. In order to mathematically model and numerically describe the fluid behaviors in injection pipelines considering injection salinity, an exploratory phase-field model is presented to simulate the multiphase flow in injection pipeline where scale formation may take place. The effect of injection salinity is represented by the scaling tendency to describe the possibility of scale formation when the scaling species are attached to the scaled structure. It can be easily referred from the simulation result that flow and scaling conditions are significantly affected if a salinity-dependent scaling tendency is considered. Thus, this mechanism should be taken into account in the design of injection process if a sustainable exploitation technique is applied by using purified production water as injection fluid. Finally, remarks and suggestions are provided based on our extensive review and preliminary investigation, to help inspire the future discussions.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"26 1","pages":"50"},"PeriodicalIF":1.5,"publicationDate":"2020-07-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82630042","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}
Moez Ben Houidi, Camille Hespel, Michele Bardi, Ob Nilaphai, L. Malbec, J. Sotton, M. Bellenoue, C. Strozzi, Hugo Ajrouche, F. Foucher, B. Moreau, C. Rousselle, G. Bruneaux
The Engine Combustion Network (ECN) community has greatly contributed to improve the fundamental understanding of spray atomization and combustion at conditions relevant to internal combustion engines. In this context, standardized spray experiments have been defined to facilitate the comparison of experimental and simulation studies performed in different facilities and with different models. This operating mode promotes collaborations among research groups and accelerates the advancement of research on spray. In efforts to improve the comparability of the ECN spray A experiments, it is of high importance to review the boundary conditions of different devices used in the community. This work is issued from the collaboration in the ECN France project, where two new experimental facilities fromPPRIME(Poitiers) andPRISME(Orleans) institutes are validated to perform spray A experiments. The two facilities, based on Rapid Compression Machine (RCM) design, have been investigated to characterize their boundary conditions (e.g., flow velocity as well as fuel and gas temperatures). A set of standardized spray experiments were performed to compare their results with those obtained in other facilities, in particular the Constant Volume Pre-burn (CVP) vessel atIFPEN. It is noteworthy that it is the first time that RCM type facilities are used in such a way within the ECN. This paper (part 1) focuses on the facilities description and the fine characterization of their boundary conditions. A further paper (part 2) will present the results obtained with the same facilities performing ECN standard spray A characterizations. The reported review of thermocouple thermometry highlights that it is necessary to use thin-wires and bare-bead junction as small as possible. This would help to measure the temperature fluctuations with a minimal need for error corrections, which are highly dependent on the proper estimation of the velocity through the junction, and therefore it may introduce important uncertainties. Temperature heterogeneities are observed in all spray A devices. The standard deviation of the temperature distribution at the time of injection is approximately 5%. We report time-resolved temperature measurement fromPPRIMERCM, performed in the near nozzle area during the injection. In inert condition, colder gases from the boundary layer are entrained toward the mixing area of the spray causing a further deviation from the target temperature. This emphasizes the importance of the temperature in the boundary (wall) layer. In reacting condition, the temperature of these entrained gases increases by the effect of the increased pressure, as the RCM has a relatively small volume. Generally, the velocity and turbulence levels are an order of magnitude higher in RCM and constant pressure flow compared to CVP vessels. The boundary characterization presented here will be the base for discussing spray behavior in the part 2 of this paper.
{"title":"Characterization of the ECN spray A in different facilities. Part 1: boundary conditions characterization","authors":"Moez Ben Houidi, Camille Hespel, Michele Bardi, Ob Nilaphai, L. Malbec, J. Sotton, M. Bellenoue, C. Strozzi, Hugo Ajrouche, F. Foucher, B. Moreau, C. Rousselle, G. Bruneaux","doi":"10.2516/ogst/2020023","DOIUrl":"https://doi.org/10.2516/ogst/2020023","url":null,"abstract":"The Engine Combustion Network (ECN) community has greatly contributed to improve the fundamental understanding of spray atomization and combustion at conditions relevant to internal combustion engines. In this context, standardized spray experiments have been defined to facilitate the comparison of experimental and simulation studies performed in different facilities and with different models. This operating mode promotes collaborations among research groups and accelerates the advancement of research on spray. In efforts to improve the comparability of the ECN spray A experiments, it is of high importance to review the boundary conditions of different devices used in the community. This work is issued from the collaboration in the ECN France project, where two new experimental facilities fromPPRIME(Poitiers) andPRISME(Orleans) institutes are validated to perform spray A experiments. The two facilities, based on Rapid Compression Machine (RCM) design, have been investigated to characterize their boundary conditions (e.g., flow velocity as well as fuel and gas temperatures). A set of standardized spray experiments were performed to compare their results with those obtained in other facilities, in particular the Constant Volume Pre-burn (CVP) vessel atIFPEN. It is noteworthy that it is the first time that RCM type facilities are used in such a way within the ECN. This paper (part 1) focuses on the facilities description and the fine characterization of their boundary conditions. A further paper (part 2) will present the results obtained with the same facilities performing ECN standard spray A characterizations. The reported review of thermocouple thermometry highlights that it is necessary to use thin-wires and bare-bead junction as small as possible. This would help to measure the temperature fluctuations with a minimal need for error corrections, which are highly dependent on the proper estimation of the velocity through the junction, and therefore it may introduce important uncertainties. Temperature heterogeneities are observed in all spray A devices. The standard deviation of the temperature distribution at the time of injection is approximately 5%. We report time-resolved temperature measurement fromPPRIMERCM, performed in the near nozzle area during the injection. In inert condition, colder gases from the boundary layer are entrained toward the mixing area of the spray causing a further deviation from the target temperature. This emphasizes the importance of the temperature in the boundary (wall) layer. In reacting condition, the temperature of these entrained gases increases by the effect of the increased pressure, as the RCM has a relatively small volume. Generally, the velocity and turbulence levels are an order of magnitude higher in RCM and constant pressure flow compared to CVP vessels. The boundary characterization presented here will be the base for discussing spray behavior in the part 2 of this paper.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"41 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89986347","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}
Numerical modeling of two-phase flows in heterogeneous and fractured media is of great interest in petroleum reservoir engineering. The classical model for two-phase flows in porous media is not completely thermodynamically consistent since the energy reconstructed from the capillary pressure does not involve the ideal fluid energy of both phases and attraction effect between two phases. On the other hand, the saturation may be discontinuous in heterogeneous and fractured media, and thus the saturation gradient may be not well defined. Consequently, the classical phase-field models can not be applied due to the use of diffuse interfaces. In this paper, we propose a new thermodynamically consistent energy-based model for two-phase flows in heterogeneous and fractured media, which is free of the gradient energy. Meanwhile, the model inherits the key features of the traditional models of two-phase flows in porous media, including relative permeability, volumetric phase velocity and capillarity effect. To characterize the capillarity effect, a logarithmic energy potential is proposed as the free energy function, which is more realistic than the commonly used double well potential. The model combines with the discrete fracture model to describe two-phase flows in fractured media. The popularly used implicit pressure explicit saturation method is used to simulate the model. Finally, the experimental verification of the model and numerical simulation results are provided.
{"title":"Thermodynamically consistent modeling of two-phase incompressible flows in heterogeneous and fractured media","authors":"Huicai Gao, Jisheng Kou, Shuyu Sun, Xiuhua Wang","doi":"10.2516/ogst/2020024","DOIUrl":"https://doi.org/10.2516/ogst/2020024","url":null,"abstract":"Numerical modeling of two-phase flows in heterogeneous and fractured media is of great interest in petroleum reservoir engineering. The classical model for two-phase flows in porous media is not completely thermodynamically consistent since the energy reconstructed from the capillary pressure does not involve the ideal fluid energy of both phases and attraction effect between two phases. On the other hand, the saturation may be discontinuous in heterogeneous and fractured media, and thus the saturation gradient may be not well defined. Consequently, the classical phase-field models can not be applied due to the use of diffuse interfaces. In this paper, we propose a new thermodynamically consistent energy-based model for two-phase flows in heterogeneous and fractured media, which is free of the gradient energy. Meanwhile, the model inherits the key features of the traditional models of two-phase flows in porous media, including relative permeability, volumetric phase velocity and capillarity effect. To characterize the capillarity effect, a logarithmic energy potential is proposed as the free energy function, which is more realistic than the commonly used double well potential. The model combines with the discrete fracture model to describe two-phase flows in fractured media. The popularly used implicit pressure explicit saturation method is used to simulate the model. Finally, the experimental verification of the model and numerical simulation results are provided.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"12 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78883800","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 this work, we introduce a theoretical foundation of the stability analysis of the mixed finite element solution to the problem of shale-gas transport in fractured porous media with geomechanical effects. The differential system was solved numerically by the Mixed Finite Element Method (MFEM). The results include seven lemmas and a theorem with rigorous mathematical proofs. The stability analysis presents the boundedness condition of the MFE solution.
{"title":"Theoretical stability analysis of mixed finite element model of shale-gas flow with geomechanical effect","authors":"M. El-Amin, Jisheng Kou, Shuyu Sun","doi":"10.2516/ogst/2020025","DOIUrl":"https://doi.org/10.2516/ogst/2020025","url":null,"abstract":"In this work, we introduce a theoretical foundation of the stability analysis of the mixed finite element solution to the problem of shale-gas transport in fractured porous media with geomechanical effects. The differential system was solved numerically by the Mixed Finite Element Method (MFEM). The results include seven lemmas and a theorem with rigorous mathematical proofs. The stability analysis presents the boundedness condition of the MFE solution.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"207 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72595308","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}
Natural gas is the fastest-growing fossil fuel and LNG is playing a growing role in the world’s gas supply. The liquefaction process is also by far the most energy-consuming part of the LNG chain. It is thus a priority today for the gas industry to decrease the cost and improve the efficiency of the liquefaction process of a plant. In this way, a novel techno-economic evolution of an existing NGL plant with adding an appropriate LNG production part is presented. Concerning the availability of propane, use of existing equipments and conditions of no structural changes in the existing installation, C3MR is used as the refrigeration system. For full recognition of the process, a high-accuracy surrogate model based on D-optimal approach is developed. MR composition (nitrogen, methane, ethane, and propane), inlet gas pressure of the LNG production part, demethanizer pressure, and high and low pressure of MR as the eight manipulated variables of the surrogate model predict the earned profit of the integrated plant. To increase profit, a hybrid GA-SQP optimization method is used. The results show that the earned profit of the optimized proposed plant with the LNG production capacity of 3.33 MTPA is 60.2% more than the existing NGL plant. In addition to increased earned profit, the thermodynamic efficiency is improved in the liquefaction section, too. Furthermore, the SPC value of 0.347 kWh kg−1 LNG shows that the optimized plant has acceptable liquefaction efficiency. According to the optimization results, mixture variables are more effective than process variables on the earned profit. It is noticeable that increasing the ethane recovery not always increases profit in such integrated units.
{"title":"Techno-economic evolution of an existing operational NGL plant with adding LNG production part","authors":"O. Sabbagh, M. Fanaei, A. Arjomand","doi":"10.2516/ogst/2020018","DOIUrl":"https://doi.org/10.2516/ogst/2020018","url":null,"abstract":"Natural gas is the fastest-growing fossil fuel and LNG is playing a growing role in the world’s gas supply. The liquefaction process is also by far the most energy-consuming part of the LNG chain. It is thus a priority today for the gas industry to decrease the cost and improve the efficiency of the liquefaction process of a plant. In this way, a novel techno-economic evolution of an existing NGL plant with adding an appropriate LNG production part is presented. Concerning the availability of propane, use of existing equipments and conditions of no structural changes in the existing installation, C3MR is used as the refrigeration system. For full recognition of the process, a high-accuracy surrogate model based on D-optimal approach is developed. MR composition (nitrogen, methane, ethane, and propane), inlet gas pressure of the LNG production part, demethanizer pressure, and high and low pressure of MR as the eight manipulated variables of the surrogate model predict the earned profit of the integrated plant. To increase profit, a hybrid GA-SQP optimization method is used. The results show that the earned profit of the optimized proposed plant with the LNG production capacity of 3.33 MTPA is 60.2% more than the existing NGL plant. In addition to increased earned profit, the thermodynamic efficiency is improved in the liquefaction section, too. Furthermore, the SPC value of 0.347 kWh kg−1 LNG shows that the optimized plant has acceptable liquefaction efficiency. According to the optimization results, mixture variables are more effective than process variables on the earned profit. It is noticeable that increasing the ethane recovery not always increases profit in such integrated units.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"63 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-01-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75029511","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 the last two decades, new technologies have been introduced to equip wells with intelligent completions such as Inflow Control Device (ICD) or Inflow Control Valve (ICV) in order to optimize the oil recovery by reducing the undesirable production of gas and water. To optimally define the locations of the packers and the characteristics of the valves, efficient reservoir simulation models are required. This paper is aimed at presenting the specific developments introduced in a multipurpose industrial reservoir simulator to simulate such wells equipped with intelligent completions taking into account the pressure drop and multiphase flow. An explicit coupling or decoupling of a reservoir model and a well flow model with intelligent completion makes usually unstable and non-convergent results, and a fully implicit coupling is CPU time consuming and difficult to be implemented. This paper presents therefore a semi-implicit approach, which links on one side to the reservoir simulation model and on the other side to the well flow model, to integrate ICD and ICV.
{"title":"A semi-implicit approach for the modeling of wells with inflow control completions","authors":"E. Flauraud, D. Ding","doi":"10.2516/ogst/2020034","DOIUrl":"https://doi.org/10.2516/ogst/2020034","url":null,"abstract":"In the last two decades, new technologies have been introduced to equip wells with intelligent completions such as Inflow Control Device (ICD) or Inflow Control Valve (ICV) in order to optimize the oil recovery by reducing the undesirable production of gas and water. To optimally define the locations of the packers and the characteristics of the valves, efficient reservoir simulation models are required. This paper is aimed at presenting the specific developments introduced in a multipurpose industrial reservoir simulator to simulate such wells equipped with intelligent completions taking into account the pressure drop and multiphase flow. An explicit coupling or decoupling of a reservoir model and a well flow model with intelligent completion makes usually unstable and non-convergent results, and a fully implicit coupling is CPU time consuming and difficult to be implemented. This paper presents therefore a semi-implicit approach, which links on one side to the reservoir simulation model and on the other side to the well flow model, to integrate ICD and ICV.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"18 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80391450","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}
Maintaining the reservoir pressure by gas injection is frequently adopted in the development of gas condensate reservoir. The aim of this work is to investigate the phase behavior of condensate oil and remaining condensate gas in the formation under gas injection. The DZT gas condensate reservoir in East China is taken as an example. The multiple contact calculation based on cell-to-cell method and phase equilibrium calculations based on PR Equation of State (EOS) were utilized to evaluate the displacement mechanism and phase behavior change. The research results show that different pure gas has different miscible mechanism in the displacement of condensate oil: vaporizing gas drive for N2 and CH4; condensing gas drive for CO2 and C2H6. Meanwhile, there is a vaporing gas drive rather than a condensing gas drive for injecting produced gas. When the condensate oil is mixed with 0.44 mole fraction of produced gas, the phase behavior of the petroleum mixture reverses, and the condensate oil is converted to condensate gas. About the reinjection of produced gas, the enrichment ability of hydrocarbons is better than that of no-hydrocarbons. After injecting produced gas, retrograde condensation is more difficult to occur, and the remaining condensate gas develops toward dry gas.
{"title":"An evaluation on phase behaviors of gas condensate reservoir in cyclic gas injection","authors":"Angang Zhang, Zi-fei Fan, Lun Zhao, Anzhu Xu","doi":"10.2516/ogst/2019070","DOIUrl":"https://doi.org/10.2516/ogst/2019070","url":null,"abstract":"Maintaining the reservoir pressure by gas injection is frequently adopted in the development of gas condensate reservoir. The aim of this work is to investigate the phase behavior of condensate oil and remaining condensate gas in the formation under gas injection. The DZT gas condensate reservoir in East China is taken as an example. The multiple contact calculation based on cell-to-cell method and phase equilibrium calculations based on PR Equation of State (EOS) were utilized to evaluate the displacement mechanism and phase behavior change. The research results show that different pure gas has different miscible mechanism in the displacement of condensate oil: vaporizing gas drive for N2 and CH4; condensing gas drive for CO2 and C2H6. Meanwhile, there is a vaporing gas drive rather than a condensing gas drive for injecting produced gas. When the condensate oil is mixed with 0.44 mole fraction of produced gas, the phase behavior of the petroleum mixture reverses, and the condensate oil is converted to condensate gas. About the reinjection of produced gas, the enrichment ability of hydrocarbons is better than that of no-hydrocarbons. After injecting produced gas, retrograde condensation is more difficult to occur, and the remaining condensate gas develops toward dry gas.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"1 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78807029","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}
Mina Kalateh-Aghamohammadi, J. Qajar, F. Esmaeilzadeh
Excessive water production from hydrocarbon reservoirs is considered as one of major problems, which has numerous economic and environmental consequences. Polymer-gel remediation has been widely used to reduce excessive water production during oil and gas recovery by plugging high permeability zones and improving conformance control. In this paper, we investigate the performance of a HPAM/PEI (water-soluble Hydrolyzed PolyAcrylaMide/PolyEthyleneImine) polymer-gel system for pore space blockage and permeability reduction for conformance control purpose. First, the gel optimum composition, resistance to salt and long life time are determined using bottle tests as a standard method to specify polymer-gel properties. Then the performance and stability of the optimized polymer-gel are tested experimentally using coreflood tests in sandpack core samples. The effects of different parameters such as gel concentration, initial permeability of the cores, and formation water salinity on the final permeability of the cores are examined. Finally, the gel flow-induced local porosity changes are studied in both a sandpack core and a real carbonate sample using grayscale intensity data provided from 3D Computed Tomography (CT) images in pre- and post-treatment states. The results show that the gel system has a good strength at the middle formation water salinity (in the range of typical sea water salinity). In addition, despite a higher performance in high permeability cores, the gel resistance to degradation in such porous media is reduced. The CT images reveal that the initial porosity distribution has a great influence on the performance of the gel to block the pore space.
{"title":"Experimental evaluation and tomographic characterization of polymer gel conformance treatment","authors":"Mina Kalateh-Aghamohammadi, J. Qajar, F. Esmaeilzadeh","doi":"10.2516/ogst/2020060","DOIUrl":"https://doi.org/10.2516/ogst/2020060","url":null,"abstract":"Excessive water production from hydrocarbon reservoirs is considered as one of major problems, which has numerous economic and environmental consequences. Polymer-gel remediation has been widely used to reduce excessive water production during oil and gas recovery by plugging high permeability zones and improving conformance control. In this paper, we investigate the performance of a HPAM/PEI (water-soluble Hydrolyzed PolyAcrylaMide/PolyEthyleneImine) polymer-gel system for pore space blockage and permeability reduction for conformance control purpose. First, the gel optimum composition, resistance to salt and long life time are determined using bottle tests as a standard method to specify polymer-gel properties. Then the performance and stability of the optimized polymer-gel are tested experimentally using coreflood tests in sandpack core samples. The effects of different parameters such as gel concentration, initial permeability of the cores, and formation water salinity on the final permeability of the cores are examined. Finally, the gel flow-induced local porosity changes are studied in both a sandpack core and a real carbonate sample using grayscale intensity data provided from 3D Computed Tomography (CT) images in pre- and post-treatment states. The results show that the gel system has a good strength at the middle formation water salinity (in the range of typical sea water salinity). In addition, despite a higher performance in high permeability cores, the gel resistance to degradation in such porous media is reduced. The CT images reveal that the initial porosity distribution has a great influence on the performance of the gel to block the pore space.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"4 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87375214","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}
Intraformational water zones are widely reported in Canadian oil sands fields. In order to pressurize a thief zone, one of the initiatives is to inject gas. However, the evaluation of gas injectivity based on a pore size distribution is still a big challenge. This study provides a multi-scale approach to study the effect of a pore size distribution on gas injectivity in intraformational water zones. The results indicate the gas effective permeability increases in a less complex and more discrete pore network. The enhancement of gas effective permeability with increased gas saturation weakens with higher complexity and lower discreteness of a pore network. A less complex and more discrete pore network better benefits the gas injectivity index.
{"title":"Impacts of pore size distribution on gas injection in intraformational water zones in oil sands reservoirs","authors":"Jinze Xu, Zhangxin Chen, Ran Li","doi":"10.2516/ogst/2020047","DOIUrl":"https://doi.org/10.2516/ogst/2020047","url":null,"abstract":"Intraformational water zones are widely reported in Canadian oil sands fields. In order to pressurize a thief zone, one of the initiatives is to inject gas. However, the evaluation of gas injectivity based on a pore size distribution is still a big challenge. This study provides a multi-scale approach to study the effect of a pore size distribution on gas injectivity in intraformational water zones. The results indicate the gas effective permeability increases in a less complex and more discrete pore network. The enhancement of gas effective permeability with increased gas saturation weakens with higher complexity and lower discreteness of a pore network. A less complex and more discrete pore network better benefits the gas injectivity index.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"36 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81342097","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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