Mahamudul Hashan, Tareq Uz Zaman, Labiba Jahan, Murtada A. Elhaj, S. Imtiaz, M. Hossain
Reservoir properties (e.g., porosity, permeability, surface tension, viscosity, fluid saturation, wettability, reservoir thickness, pressure, and temperature) are the function of time. Time variation of rock-fluid properties in a reservoir can be defined as memory concept in the field of petroleum engineering. Introducing memory formalism in reservoir simulation allows to account the time-varying nature of rock-fluid properties and enables reservoir simulator to provide more accurate reservoir flow forecast. The key purpose of this paper is to summarize the details for developing a memory formalism-based reservoir simulator. Within the context of the study, the key concept of memory formalism and fractional calculus are precisely explained. A complete roadmap in preparing a memory formalism-based reservoir simulator is shown with example and application.
{"title":"Application of Memory Formalism and Fractional Derivative in Reservoir Simulation","authors":"Mahamudul Hashan, Tareq Uz Zaman, Labiba Jahan, Murtada A. Elhaj, S. Imtiaz, M. Hossain","doi":"10.2118/191213-MS","DOIUrl":"https://doi.org/10.2118/191213-MS","url":null,"abstract":"\u0000 Reservoir properties (e.g., porosity, permeability, surface tension, viscosity, fluid saturation, wettability, reservoir thickness, pressure, and temperature) are the function of time. Time variation of rock-fluid properties in a reservoir can be defined as memory concept in the field of petroleum engineering. Introducing memory formalism in reservoir simulation allows to account the time-varying nature of rock-fluid properties and enables reservoir simulator to provide more accurate reservoir flow forecast. The key purpose of this paper is to summarize the details for developing a memory formalism-based reservoir simulator. Within the context of the study, the key concept of memory formalism and fractional calculus are precisely explained. A complete roadmap in preparing a memory formalism-based reservoir simulator is shown with example and application.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115120885","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mahamudul Hashan, Labiba Jahan, Tareq Uz Zaman, Murtada A. Elhaj, S. Imtiaz, M. Hossain
The mathematical approach is the most commonly used approach in reservoir simulation. The classical mathematical approach considers numerous impractical assumptions leading toward the development of unrealistic reservoir simulator. In contrast, recently developed engineering approach is much promising as it has numerous advantages, such as – scope of bypassing the formulation of partial differential equations and discretization of partial differential equations, the ability to avoid rigorous and complex mathematics, and capability of realistic representation of reservoir behaviour through eliminating spurious assumptions. The present study outlines the route map for developing a reservoir simulator using an engineering approach. Major challenges encountered in reservoir simulation and the fundamentals of various available modelling approaches are addressed in this paper. The outlook for both classical mathematical approach and engineering approach are reviewed along with their strengths and weaknesses. Fluid flow equations are derived based on the proposed engineering approach. To do that, a set of non-linear algebraic flow equations in the time integral form is developed using the mass balance equation, an equation of state, and a constitutive equation without going through the formulation of partial differential equations and discretization step. The time integral is then approximated to obtain the non-linear algebraic flow equations for all the gridblocks of the reservoir. The significance of the engineering approach for describing the accurate fluid flow through porous media is compared to the to conventional mathematical approach. The engineering approach provides the same fluid flow equations as the classical mathematical approach for both the radial cylindrical and cartesian coordinate system but, without going through the formulation of partial differential equations and discretization step. Much simpler ordinary differential equation solvers, e.g., Runge-Kutta method or Euler method can be used in the engineering approach to obtain the solution, whereas the classical mathematical approach does not have this advantage. Both the classical mathematical approach and the engineering approach treat the initial conditions in the same way. If classical mathematical approach uses second-order approximation then the same accuracy is obtained for both approaches in treating the boundary conditions. The engineering approach provides more precise dealing to the constant pressure boundary condition for block-centred gridding system in case of using the first-order approximation. The engineering approach gives the justification of using the central difference approximation for second order space derivative in classical mathematical approach. Results show that the proposed engineering approach based fluid flow model provides better flow prediction than the conventional mathematical approach based flow model. The outcome of this study will help enginee
{"title":"Modelling of Fluid Flow in a Petroleum Reservoir Using an Engineering Approach","authors":"Mahamudul Hashan, Labiba Jahan, Tareq Uz Zaman, Murtada A. Elhaj, S. Imtiaz, M. Hossain","doi":"10.2118/191153-MS","DOIUrl":"https://doi.org/10.2118/191153-MS","url":null,"abstract":"\u0000 The mathematical approach is the most commonly used approach in reservoir simulation. The classical mathematical approach considers numerous impractical assumptions leading toward the development of unrealistic reservoir simulator. In contrast, recently developed engineering approach is much promising as it has numerous advantages, such as – scope of bypassing the formulation of partial differential equations and discretization of partial differential equations, the ability to avoid rigorous and complex mathematics, and capability of realistic representation of reservoir behaviour through eliminating spurious assumptions. The present study outlines the route map for developing a reservoir simulator using an engineering approach. Major challenges encountered in reservoir simulation and the fundamentals of various available modelling approaches are addressed in this paper. The outlook for both classical mathematical approach and engineering approach are reviewed along with their strengths and weaknesses. Fluid flow equations are derived based on the proposed engineering approach. To do that, a set of non-linear algebraic flow equations in the time integral form is developed using the mass balance equation, an equation of state, and a constitutive equation without going through the formulation of partial differential equations and discretization step. The time integral is then approximated to obtain the non-linear algebraic flow equations for all the gridblocks of the reservoir. The significance of the engineering approach for describing the accurate fluid flow through porous media is compared to the to conventional mathematical approach. The engineering approach provides the same fluid flow equations as the classical mathematical approach for both the radial cylindrical and cartesian coordinate system but, without going through the formulation of partial differential equations and discretization step. Much simpler ordinary differential equation solvers, e.g., Runge-Kutta method or Euler method can be used in the engineering approach to obtain the solution, whereas the classical mathematical approach does not have this advantage. Both the classical mathematical approach and the engineering approach treat the initial conditions in the same way. If classical mathematical approach uses second-order approximation then the same accuracy is obtained for both approaches in treating the boundary conditions. The engineering approach provides more precise dealing to the constant pressure boundary condition for block-centred gridding system in case of using the first-order approximation. The engineering approach gives the justification of using the central difference approximation for second order space derivative in classical mathematical approach. Results show that the proposed engineering approach based fluid flow model provides better flow prediction than the conventional mathematical approach based flow model. The outcome of this study will help enginee","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122854483","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study assessed the impact of static and dynamic variables in EUR and NPV in the development plan of a North Sea offshore field with 81 m of water, light oil crude of 40.5 API and 510 SCF/STB of GOR comprised of sandstones from a shallow marine environment in anticline structure separated to the northeast and southwest by a pair of normal faults. The analysis is conducted through the application of different experimental design techniques and the preparation of a comparison between them. Uncertainty analysis has been prepared to characterize the appropriate range for nine variables that affect the oil recovery and net present value of the field development. A Folded Plackett-Burman design was prepared to screen the initial nine variables; the linear regression results show that the oil water contact, permeability anisotropy and net to gross are the significant variables. Also, the residual analysis demonstrated that the proxy equation should be improved to have better predictability in the non-sampled space. In consequence, a D-Optimal and a Central Composite experimental design were prepared for the three significant variables. The regression results show better coefficient correlation and lower least square errors in the D-Optimal design using a full quadratic model and confirmed the oil water contact as the most significant variable of the field. Finally, Monte Carlo Simulation was performed in the proxy model from the D-Optimal design, which resulted in an expected value ultimate recovery of 357 MMSTB. The paper presents an exciting workflow to analyze different experimental design techniques, compare them and use the most suitable to prepare the development plan of a field.
{"title":"Uncertainty Analysis using Design of Experiments to Assess the Development Plan of a North Sea Field","authors":"A. Guerrero, K. Stephen","doi":"10.2118/191244-MS","DOIUrl":"https://doi.org/10.2118/191244-MS","url":null,"abstract":"\u0000 This study assessed the impact of static and dynamic variables in EUR and NPV in the development plan of a North Sea offshore field with 81 m of water, light oil crude of 40.5 API and 510 SCF/STB of GOR comprised of sandstones from a shallow marine environment in anticline structure separated to the northeast and southwest by a pair of normal faults. The analysis is conducted through the application of different experimental design techniques and the preparation of a comparison between them. Uncertainty analysis has been prepared to characterize the appropriate range for nine variables that affect the oil recovery and net present value of the field development. A Folded Plackett-Burman design was prepared to screen the initial nine variables; the linear regression results show that the oil water contact, permeability anisotropy and net to gross are the significant variables. Also, the residual analysis demonstrated that the proxy equation should be improved to have better predictability in the non-sampled space. In consequence, a D-Optimal and a Central Composite experimental design were prepared for the three significant variables. The regression results show better coefficient correlation and lower least square errors in the D-Optimal design using a full quadratic model and confirmed the oil water contact as the most significant variable of the field. Finally, Monte Carlo Simulation was performed in the proxy model from the D-Optimal design, which resulted in an expected value ultimate recovery of 357 MMSTB. The paper presents an exciting workflow to analyze different experimental design techniques, compare them and use the most suitable to prepare the development plan of a field.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125881695","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks. A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples. Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
{"title":"Property Changes of Formation Rocks under Electromagnetic Heating: An Experimental Study","authors":"Lanxiao Hu, H. Li, T. Babadagli","doi":"10.2118/191238-MS","DOIUrl":"https://doi.org/10.2118/191238-MS","url":null,"abstract":"\u0000 Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks.\u0000 A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples.\u0000 Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123691232","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
An integrated benchmarking and screening study of IOR/EOR technologies used in analogous reservoirs worldwide was performed in the Southwest Soldado (SWS) Field offshore Trinidad, in order to establish the top three methods which could be implemented in this field to increase the recovery factor after more than 30 years producing under primary conditions. The evaluation of IOR/EOR processes for the Southwest Soldado Field was done in 2 stages. Stage 1 included screening of processes to identify the top 3 methods to be used. Stage 2 involved the detailed evaluation of the top 3 processes. For Stage 1, the National Petroleum Council EOR Screening Method was used along with innovative techniques recommended by industry literature (Taber et al., 1997, Pérez-Pérez et al., 2001). In Stage 2, standard statistical methods were applied to the compiled database of successful IOR/EOR projects in offshore sandstone reservoirs. That information was used to establish a predicted recovery factor for the top 3 IOR/EOR methods selected. A theoretical description of the selected methods and their relationship with Southwest Soldado characteristics was done. Finally, considerations for pilot projects with recommended facilities, required logistics and cost estimates were analyzed and the best options were recommended. Given the characteristics of the Southwest Soldado field, Water Alternate Gas (WAG) injection resulted with the highest score based on the benchmarking exercise; Carbon dioxide (CO2) injection and water injection were selected in second and third place respectively. In the case of CO2, it was recommended as Huff and Puff in order to delineate transition zones, for ease of application in existing wells and facilities and for comparatively low cost. This method also generates high oil recoveries in a relative short period of time. Finally, it was recommended that for the implementation of a pilot project, Huff and Puff CO2 injection should be tested prior to WAG injection due to the many advantages in evaluating the reservoirs, quick execution and rapid production results at the lowest investment cost from the other 2 methods evaluated. This paper presents the steps taken to benchmark an offshore field in Trinidad using the field's actual data. It lays the foundation for further development of heavy oil reserves in Southwest Soldado, highlights the challenges based on infrastructure, technology and economics requirements and provides a roadmap to further increase the recovery factor of these offshore heavy oil reservoirs.
在特立尼达海上的西南Soldado (SWS)油田，对全球类似油藏中使用的IOR/EOR技术进行了综合基准测试和筛选研究，以确定该油田在原始条件下生产30多年后提高采收率的最佳三种方法。对西南Soldado油田的IOR/EOR工艺进行了两个阶段的评估。第一阶段包括筛选过程，以确定最常用的3种方法。第二阶段包括对前3个过程的详细评价。在第一阶段，使用国家石油委员会EOR筛选方法以及行业文献推荐的创新技术(Taber et al.， 1997; psamrez - psamrez et al.， 2001)。在第二阶段，将标准统计方法应用于编制的海上砂岩储层IOR/EOR成功项目数据库。这些信息被用来为选择的前3种IOR/EOR方法建立预测的采收率。对所选择的方法及其与西南索尔达多特征的关系进行了理论描述。最后，分析了具有推荐设施、所需物流和成本估算的试点项目的考虑因素，并提出了最佳选择。考虑到西南Soldado油田的特点，在基准测试中，水替代气(WAG)注入获得了最高的分数;二氧化碳(CO2)注入和水注入分别被选为第二和第三名。在二氧化碳的情况下，建议使用Huff和Puff来划定过渡区，以便于在现有的井和设施中应用，并且成本相对较低。这种方法还可以在相对较短的时间内实现高采收率。最后，对于试点项目的实施，建议在WAG注入之前进行Huff和Puff CO2注入测试，因为与其他两种评估方法相比，这两种方法在评估储层、快速执行和快速产出结果方面具有许多优势，投资成本最低。本文介绍了利用特立尼达海上油田的实际数据进行基准测试所采取的步骤。为进一步开发Soldado西南部稠油储量奠定了基础，突出了基础设施、技术和经济要求方面的挑战，并为进一步提高海上稠油油藏的采收率提供了路线图。
{"title":"Integrated IOR/EOR Screening of an Offshore Oilfield in Trinidad","authors":"C. Garcia-james","doi":"10.2118/191176-MS","DOIUrl":"https://doi.org/10.2118/191176-MS","url":null,"abstract":"\u0000 \u0000 \u0000 An integrated benchmarking and screening study of IOR/EOR technologies used in analogous reservoirs worldwide was performed in the Southwest Soldado (SWS) Field offshore Trinidad, in order to establish the top three methods which could be implemented in this field to increase the recovery factor after more than 30 years producing under primary conditions.\u0000 \u0000 \u0000 \u0000 The evaluation of IOR/EOR processes for the Southwest Soldado Field was done in 2 stages. Stage 1 included screening of processes to identify the top 3 methods to be used. Stage 2 involved the detailed evaluation of the top 3 processes. For Stage 1, the National Petroleum Council EOR Screening Method was used along with innovative techniques recommended by industry literature (Taber et al., 1997, Pérez-Pérez et al., 2001). In Stage 2, standard statistical methods were applied to the compiled database of successful IOR/EOR projects in offshore sandstone reservoirs. That information was used to establish a predicted recovery factor for the top 3 IOR/EOR methods selected. A theoretical description of the selected methods and their relationship with Southwest Soldado characteristics was done. Finally, considerations for pilot projects with recommended facilities, required logistics and cost estimates were analyzed and the best options were recommended.\u0000 \u0000 \u0000 \u0000 Given the characteristics of the Southwest Soldado field, Water Alternate Gas (WAG) injection resulted with the highest score based on the benchmarking exercise; Carbon dioxide (CO2) injection and water injection were selected in second and third place respectively. In the case of CO2, it was recommended as Huff and Puff in order to delineate transition zones, for ease of application in existing wells and facilities and for comparatively low cost. This method also generates high oil recoveries in a relative short period of time. Finally, it was recommended that for the implementation of a pilot project, Huff and Puff CO2 injection should be tested prior to WAG injection due to the many advantages in evaluating the reservoirs, quick execution and rapid production results at the lowest investment cost from the other 2 methods evaluated.\u0000 \u0000 \u0000 \u0000 This paper presents the steps taken to benchmark an offshore field in Trinidad using the field's actual data. It lays the foundation for further development of heavy oil reserves in Southwest Soldado, highlights the challenges based on infrastructure, technology and economics requirements and provides a roadmap to further increase the recovery factor of these offshore heavy oil reservoirs.\u0000","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128788707","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Y. Miao, John W. Lee, Chaojie Zhao, Wenjing Lin, Hang Li, Yucui Chang, Yunjian Zhou, Xiangfang Li
Estimating stimulated reservoir volume (SRV) in shale gas reservoirs with high accuracy has been of more concern to oil and gas industries. However, current SRV prediction methods are of limited use for characterizing critical flow mechanisms. To make more accurate prediction of SRV in shale gas reservoirs, multiple mechanisms cannot be ignored. In this paper, we develop a novel analytical model to accurately estimate the volume of SRV in shale gas reserviors by incorporating both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas directly into the model. Depending on flow discrepancies from conventional reservoirs, the modified pseudo-pressure equation to account for these critical transport mechanisms are further constructed. Predicted values of SRV by using this new model are in fair agreement with values from the CMG simulation. Compared with related research, it is the first time that both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas are taken into consdertion to analyze and estimate the volume of SRV in shale gas reservoirs. A clear workflow for implementation of this method is presented. Compared with the common numerical reservoir simulators, this approach is easier to setup and less data-intensive.
{"title":"A Practical Method for Estimating Stimulated Reservoir Volume in Shale Gas Reservoirs: Coupling Knudsen Diffusion and Surface Diffusion","authors":"Y. Miao, John W. Lee, Chaojie Zhao, Wenjing Lin, Hang Li, Yucui Chang, Yunjian Zhou, Xiangfang Li","doi":"10.2118/191237-MS","DOIUrl":"https://doi.org/10.2118/191237-MS","url":null,"abstract":"\u0000 Estimating stimulated reservoir volume (SRV) in shale gas reservoirs with high accuracy has been of more concern to oil and gas industries. However, current SRV prediction methods are of limited use for characterizing critical flow mechanisms. To make more accurate prediction of SRV in shale gas reservoirs, multiple mechanisms cannot be ignored. In this paper, we develop a novel analytical model to accurately estimate the volume of SRV in shale gas reserviors by incorporating both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas directly into the model. Depending on flow discrepancies from conventional reservoirs, the modified pseudo-pressure equation to account for these critical transport mechanisms are further constructed. Predicted values of SRV by using this new model are in fair agreement with values from the CMG simulation. Compared with related research, it is the first time that both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas are taken into consdertion to analyze and estimate the volume of SRV in shale gas reservoirs. A clear workflow for implementation of this method is presented. Compared with the common numerical reservoir simulators, this approach is easier to setup and less data-intensive.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117346062","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
G. Peña, Humberto Chaparro, I. Rodriguez, E. Azuaje
Design a completion system for sand control based on top technology as an alternative to the slotted-liner completions systems currently installed in extra heavy oil producing wells in unconsolidated formations. The methodology and design are based on the resulting interpretations of Dry Sieve Analysis (DSA), Laser Particle Sieve Analysis (LPSA), and geological considerations. Based on the results of these analyses, uniformity coefficients were calculated and grain size sorting results were used to validate the completion criteria, the system type, and the open area to be used. Once these criterions were selected, the Sand Retention Test (SRT) was utilized in the laboratory to verify the performance of the design using different liner sections and core plugs specific to the area; which allowed the selection of the appropriate system. Quantifying the total recovered barrels with the new completion system was done using a nodal analysis in order to evaluate the cost benefit in a typical well. As result of the interpretations of the tests, it was determined that the open area size of the completion system should be 200 μm, being estimated by the D10 obtained by the DSA realized to the core "A" of the Lower Morichal Formation. With the LPSA realized to the core "B", the quantity of thin grain movables less than 45 μm was estimated for the Lower Morichal Formation. All of these criteria were unified to select the completion method best suited for sand control. The results shows that the best option is metal mesh screen, which offer 150% more flow area in comparison with the slotted liner which translates to a recovery of 10% in production according to nodal analysis simulations. While current design practices sometimes take into consideration grain size distribution and sorting, this paper highlights the added benefit of combining this approach with the laboratory results of the DSA and LPSA testing methods to ensure that production recovery is truly maximized.
{"title":"Integrated Sand Control Method Design Based on Dsa, Lpsa and Geologic Aspects","authors":"G. Peña, Humberto Chaparro, I. Rodriguez, E. Azuaje","doi":"10.2118/191227-MS","DOIUrl":"https://doi.org/10.2118/191227-MS","url":null,"abstract":"\u0000 Design a completion system for sand control based on top technology as an alternative to the slotted-liner completions systems currently installed in extra heavy oil producing wells in unconsolidated formations.\u0000 The methodology and design are based on the resulting interpretations of Dry Sieve Analysis (DSA), Laser Particle Sieve Analysis (LPSA), and geological considerations. Based on the results of these analyses, uniformity coefficients were calculated and grain size sorting results were used to validate the completion criteria, the system type, and the open area to be used. Once these criterions were selected, the Sand Retention Test (SRT) was utilized in the laboratory to verify the performance of the design using different liner sections and core plugs specific to the area; which allowed the selection of the appropriate system. Quantifying the total recovered barrels with the new completion system was done using a nodal analysis in order to evaluate the cost benefit in a typical well.\u0000 As result of the interpretations of the tests, it was determined that the open area size of the completion system should be 200 μm, being estimated by the D10 obtained by the DSA realized to the core \"A\" of the Lower Morichal Formation. With the LPSA realized to the core \"B\", the quantity of thin grain movables less than 45 μm was estimated for the Lower Morichal Formation. All of these criteria were unified to select the completion method best suited for sand control. The results shows that the best option is metal mesh screen, which offer 150% more flow area in comparison with the slotted liner which translates to a recovery of 10% in production according to nodal analysis simulations.\u0000 While current design practices sometimes take into consideration grain size distribution and sorting, this paper highlights the added benefit of combining this approach with the laboratory results of the DSA and LPSA testing methods to ensure that production recovery is truly maximized.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126595311","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system. This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
{"title":"Numerical Modeling of Water-Soluble Sodium Silicate Gel System for Fluid Diversion and Flow-Zone Isolation in Highly Heterogeneous Reservoirs","authors":"T. K. Khamees, R. Flori, Sherif Fakher","doi":"10.2118/191200-MS","DOIUrl":"https://doi.org/10.2118/191200-MS","url":null,"abstract":"\u0000 This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.\u0000 This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132687276","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The assumption of constant rate production, which is often invalid for the extended period of production, is one of the fundamental premises for current analytical approaches of temperature transient analysis. This work addressed this issue by introducing novel analytical approaches to model temperature signals under variable rate conditions. The specific methods share underlying theories of superposition principle and production rate normalization from pressure transient analysis. With adapting these methods, cases with complex production history are modelled using analog cases producing with constant rate. The analytical approach validation is performed by graphically and quantitative estimation of reservoir properties compared with synthetic temperature data. The estimation outputs of these methods include permeability, porosity, drainage area, and damaged zone properties, which are the application combinations from temperature transient analysis and reservoir limits testing. Monitoring well surveillance is extended to variable rate production in this paper. A case documented in the literature is addressed by this temperature analysis for which decent reservoir characterization results are obtained. The temperature analysis proposed in this paper extends the scope of temperature transient analysis to complex production constraints and demonstrates convincing results for practical purposes.
{"title":"Transient and Boundary Dominated Flow Temperature Analysis under Variable Rate Conditions","authors":"Y. Mao, M. Zeidouni","doi":"10.2118/191353-MS","DOIUrl":"https://doi.org/10.2118/191353-MS","url":null,"abstract":"\u0000 The assumption of constant rate production, which is often invalid for the extended period of production, is one of the fundamental premises for current analytical approaches of temperature transient analysis. This work addressed this issue by introducing novel analytical approaches to model temperature signals under variable rate conditions. The specific methods share underlying theories of superposition principle and production rate normalization from pressure transient analysis. With adapting these methods, cases with complex production history are modelled using analog cases producing with constant rate.\u0000 The analytical approach validation is performed by graphically and quantitative estimation of reservoir properties compared with synthetic temperature data. The estimation outputs of these methods include permeability, porosity, drainage area, and damaged zone properties, which are the application combinations from temperature transient analysis and reservoir limits testing. Monitoring well surveillance is extended to variable rate production in this paper. A case documented in the literature is addressed by this temperature analysis for which decent reservoir characterization results are obtained. The temperature analysis proposed in this paper extends the scope of temperature transient analysis to complex production constraints and demonstrates convincing results for practical purposes.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"61 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114719824","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Muzaffar Mohamdally, M. Soroush, M. Zeidouni, D. Alexander, Donnie Boodlal
Fault transmissibility and leakage have significant implications for field development during both primary and post-primary recovery. Whether the fault is sealing or not can directly determine the sweep efficiency and the fate of injected fluids. In addition, fault transmissivity affect the accuracy of in-place volume calculations from material balance techniques. In this paper dynamic data was used to determine transmissibility and leakage of the faults via Capacitance Model (CM). The CM has been developed from linear productivity model and material balance equation. Its inputs are production/injection rates and bottomhole pressure data (if available). The CM has weight factor for each well pair which determines the degree of connectivity between that pair. These weight factors were used and correlated to the fault transmissibility in this paper. Also, the CM was modified to incorporate the leakage in the system. New term, called leakage factor, was added for each well in the equation. The model was examined through applying to several synthetic field data generated by CMG software. In synthetic fields, different faults with different throw and transmissibility were built and across the fault transmissibility was evaluated by the model. For creating leaking fault, upward leakage and flow along the fault were examined. Estimated zero leakage factor means no leakage and one means maximum leakage for the wells. The leakage factors not only identified where the leakage was happening, but also determined the amount of leakage by multiplying leakage factor to the net accumulation. In reservoirs with complex geology and several faults, commonly encountered in Trinidad, all geological and geophysical complexities might not be accurately known. Using alternative methods such as the CM can complement, validate or better determine fault properties such as leakage and transmissibility for proper application of EOR schemes.
{"title":"Fault Leakage Assessment Using the Capacitance Model","authors":"Muzaffar Mohamdally, M. Soroush, M. Zeidouni, D. Alexander, Donnie Boodlal","doi":"10.2118/191250-MS","DOIUrl":"https://doi.org/10.2118/191250-MS","url":null,"abstract":"\u0000 Fault transmissibility and leakage have significant implications for field development during both primary and post-primary recovery. Whether the fault is sealing or not can directly determine the sweep efficiency and the fate of injected fluids. In addition, fault transmissivity affect the accuracy of in-place volume calculations from material balance techniques. In this paper dynamic data was used to determine transmissibility and leakage of the faults via Capacitance Model (CM).\u0000 The CM has been developed from linear productivity model and material balance equation. Its inputs are production/injection rates and bottomhole pressure data (if available). The CM has weight factor for each well pair which determines the degree of connectivity between that pair. These weight factors were used and correlated to the fault transmissibility in this paper. Also, the CM was modified to incorporate the leakage in the system. New term, called leakage factor, was added for each well in the equation.\u0000 The model was examined through applying to several synthetic field data generated by CMG software. In synthetic fields, different faults with different throw and transmissibility were built and across the fault transmissibility was evaluated by the model. For creating leaking fault, upward leakage and flow along the fault were examined. Estimated zero leakage factor means no leakage and one means maximum leakage for the wells. The leakage factors not only identified where the leakage was happening, but also determined the amount of leakage by multiplying leakage factor to the net accumulation.\u0000 In reservoirs with complex geology and several faults, commonly encountered in Trinidad, all geological and geophysical complexities might not be accurately known. Using alternative methods such as the CM can complement, validate or better determine fault properties such as leakage and transmissibility for proper application of EOR schemes.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116077493","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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