Songyan Li, Kexin Du, Yaohui Wei, Minghe Li, Zhoujie Wang
Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.
{"title":"Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir","authors":"Songyan Li, Kexin Du, Yaohui Wei, Minghe Li, Zhoujie Wang","doi":"10.2118/219454-pa","DOIUrl":"https://doi.org/10.2118/219454-pa","url":null,"abstract":"\u0000 Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"32 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139871434","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}
Unconventional reservoirs have nanoscale pores, complex pore structures, and heterogeneity that directly affect reservoir storage performance and fluid transport capacity. In this study, shale, mudstone, and sandstone, three typical coal sedimentary rocks from the Daqiang coal mine in the Tifa Basin, were selected for nuclear magnetic resonance (NMR) and scanning electron microscopy (SEM) investigation, with the aim to investigate the pore structure and multifractal characteristics of the coal sedimentary reservoirs and to qualitatively analyze the effects of the physical property parameters and the mineralogical compositions on the multifractal parameters. The distribution data of the NMR T2 spectra were analyzed. The results showed that (1) SEM analysis concluded that the pore system of the three different lithological samples (mudstone, shale, and sandstone) was dominated by mineral matrix pores (i.e., intergranular and intragranular pores) and in the sandstone samples, there were only a few biological pores found. (2) The distribution of the NMR T2 spectrum peaks indicates that the sandstone and shale T2 spectra are bimodal, dominated by micropores, and contain a small number of transitional pores; most of the T2 spectra of mudstone are single peaks in distribution, mainly dominated by micropores. (3) Multifractal parameters are positively correlated with porosity and significantly negatively correlated with permeability; multifractal parameters are significantly positively correlated with the content of clay minerals and kaolinite, which suggests that the increase in clay minerals and kaolinite content enhances the heterogeneity of the pore space. The negative correlation with the content of quartz suggests that the enrichment of quartz reduces the irregularity of the pore space.
{"title":"Fractal and Multifractal Characteristics on Pore Structure of Coal-Based Sedimentary Rocks Using Nuclear Magnetic Resonance","authors":"Na Zhang, Shuhui Guo, Shuaidong Wang, Yizhuo Tong, Zheng Li, Jiaqi Wu","doi":"10.2118/219457-pa","DOIUrl":"https://doi.org/10.2118/219457-pa","url":null,"abstract":"\u0000 Unconventional reservoirs have nanoscale pores, complex pore structures, and heterogeneity that directly affect reservoir storage performance and fluid transport capacity. In this study, shale, mudstone, and sandstone, three typical coal sedimentary rocks from the Daqiang coal mine in the Tifa Basin, were selected for nuclear magnetic resonance (NMR) and scanning electron microscopy (SEM) investigation, with the aim to investigate the pore structure and multifractal characteristics of the coal sedimentary reservoirs and to qualitatively analyze the effects of the physical property parameters and the mineralogical compositions on the multifractal parameters. The distribution data of the NMR T2 spectra were analyzed. The results showed that (1) SEM analysis concluded that the pore system of the three different lithological samples (mudstone, shale, and sandstone) was dominated by mineral matrix pores (i.e., intergranular and intragranular pores) and in the sandstone samples, there were only a few biological pores found. (2) The distribution of the NMR T2 spectrum peaks indicates that the sandstone and shale T2 spectra are bimodal, dominated by micropores, and contain a small number of transitional pores; most of the T2 spectra of mudstone are single peaks in distribution, mainly dominated by micropores. (3) Multifractal parameters are positively correlated with porosity and significantly negatively correlated with permeability; multifractal parameters are significantly positively correlated with the content of clay minerals and kaolinite, which suggests that the increase in clay minerals and kaolinite content enhances the heterogeneity of the pore space. The negative correlation with the content of quartz suggests that the enrichment of quartz reduces the irregularity of the pore space.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"25 12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139887095","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}
Jie Zheng, Zhihao Hu, Weixiao Wang, Yihua Dou, Jiahui Li, Xu Yang, Yarong Zhang, Yinping Cao
To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.
{"title":"Computational Fluid Dynamics Modeling and Analysis of Axial and Radial Temperature of Wellbore during Injection and Production Process","authors":"Jie Zheng, Zhihao Hu, Weixiao Wang, Yihua Dou, Jiahui Li, Xu Yang, Yarong Zhang, Yinping Cao","doi":"10.2118/219467-pa","DOIUrl":"https://doi.org/10.2118/219467-pa","url":null,"abstract":"\u0000 To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"28 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139891588","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 injection of carbon dioxide (CO2) into coal seams is a prominent technique that can provide carbon sequestration in addition to enhancing coalbed methane extraction. However, CO2 injection into the coal seams can alter the coal strength properties and their long-term integrity. In this work, the strength alteration of coals induced by CO2 exposure was modeled using 147 laboratory-measured unconfined compressive strength (UCS) data points and considering CO2 saturation pressure, CO2 interaction temperature, CO2 interaction time, and coal rank as input variables. Advanced white-box and black-box machine learning algorithms including Gaussian process regression (GPR) with rational quadratic kernel, extreme gradient boosting (XGBoost), categorical boosting (CatBoost), adaptive boosting decision tree (AdaBoost-DT), multivariate adaptive regression splines (MARS), K-nearest neighbor (KNN), gene expression programming (GEP), and group method of data handling (GMDH) were used in the modeling process. The results demonstrated that GPR-Rational Quadratic provided the most accurate estimates of UCS of coals having 3.53%, 3.62%, and 3.55% for the average absolute percent relative error (AAPRE) values of the train, test, and total data sets, respectively. Also, the overall determination coefficient (R2) value of 0.9979 was additional proof of the excellent accuracy of this model compared with other models. Moreover, the first mathematical correlations to estimate the change in coal strength induced by CO2 exposure were established in this work by the GMDH and GEP algorithms with acceptable accuracy. Sensitivity analysis revealed that the Spearman correlation coefficient shows the relative importance of the input parameters on the coal strength better than the Pearson correlation coefficient. Among the inputs, coal rank had the greatest influence on the coal strength (strong nonlinear relationship) based on the Spearman correlation coefficient. After that, CO2 interaction time and CO2 saturation pressure have shown relatively strong nonlinear relationships with model output, respectively. The CO2 interaction temperature had the smallest impact on coal strength alteration induced by CO2 exposure based on both Pearson and Spearman correlation coefficients. Finally, the leverage technique revealed that the laboratory database used for modeling CO2-induced strength alteration of coals was highly reliable, and the suggested GPR-Rational Quadratic model and GMDH correlation could be applied for predicting the UCS of coals exposed to CO2 with high statistical accuracy and reliability.
向煤层注入二氧化碳（CO2）是一项重要技术，除了能提高煤层气的提取率，还能起到固碳的作用。然而，向煤层注入二氧化碳会改变煤的强度特性及其长期完整性。在这项工作中，使用 147 个实验室测量的无压抗压强度（UCS）数据点，并将二氧化碳饱和压力、二氧化碳作用温度、二氧化碳作用时间和煤炭等级作为输入变量，对二氧化碳暴露引起的煤炭强度变化进行了建模。建模过程中使用了先进的白盒和黑盒机器学习算法，包括带有理二次核的高斯过程回归（GPR）、极梯度提升（XGBoost）、分类提升（CatBoost）、自适应提升决策树（AdaBoost-DT）、多元自适应回归样条（MARS）、K-近邻（KNN）、基因表达编程（GEP）和数据处理分组法（GMDH）。结果表明，GPR-有理四次方对煤炭 UCS 的估计最为准确，训练数据集、测试数据集和总数据集的平均绝对相对误差（AAPRE）值分别为 3.53%、3.62% 和 3.55%。此外，总体判定系数 (R2) 值为 0.9979，进一步证明了该模型与其他模型相比具有极高的准确性。此外，在这项工作中，GMDH 和 GEP 算法首次建立了估算二氧化碳暴露引起的煤炭强度变化的数学相关性，其准确性是可以接受的。敏感性分析表明，斯皮尔曼相关系数比皮尔逊相关系数更能显示输入参数对煤炭强度的相对重要性。根据斯皮尔曼相关系数，在输入参数中，煤炭等级对煤炭强度的影响最大（强非线性关系）。之后，CO2 作用时间和 CO2 饱和压力分别与模型输出显示出相对较强的非线性关系。根据 Pearson 和 Spearman 相关系数，CO2 作用温度对 CO2 暴露引起的煤炭强度变化的影响最小。最后，杠杆技术表明，用于模拟 CO2 诱导的煤炭强度变化的实验室数据库具有很高的可靠性，建议的 GPR 二次方模型和 GMDH 相关性可用于预测暴露于 CO2 的煤炭的 UCS，具有很高的统计准确性和可靠性。
{"title":"On the Evaluation of Coal Strength Alteration Induced by CO2 Injection Using Advanced Black-Box and White-Box Machine Learning Algorithms","authors":"Qichao Lv, Haimin Zheng, Xiaochen Li, Mohammad-Reza Mohammadi, Fahimeh Hadavimoghaddam, Tongke Zhou, Atena Mahmoudzadeh, A. Hemmati-Sarapardeh","doi":"10.2118/218403-pa","DOIUrl":"https://doi.org/10.2118/218403-pa","url":null,"abstract":"\u0000 The injection of carbon dioxide (CO2) into coal seams is a prominent technique that can provide carbon sequestration in addition to enhancing coalbed methane extraction. However, CO2 injection into the coal seams can alter the coal strength properties and their long-term integrity. In this work, the strength alteration of coals induced by CO2 exposure was modeled using 147 laboratory-measured unconfined compressive strength (UCS) data points and considering CO2 saturation pressure, CO2 interaction temperature, CO2 interaction time, and coal rank as input variables. Advanced white-box and black-box machine learning algorithms including Gaussian process regression (GPR) with rational quadratic kernel, extreme gradient boosting (XGBoost), categorical boosting (CatBoost), adaptive boosting decision tree (AdaBoost-DT), multivariate adaptive regression splines (MARS), K-nearest neighbor (KNN), gene expression programming (GEP), and group method of data handling (GMDH) were used in the modeling process. The results demonstrated that GPR-Rational Quadratic provided the most accurate estimates of UCS of coals having 3.53%, 3.62%, and 3.55% for the average absolute percent relative error (AAPRE) values of the train, test, and total data sets, respectively. Also, the overall determination coefficient (R2) value of 0.9979 was additional proof of the excellent accuracy of this model compared with other models. Moreover, the first mathematical correlations to estimate the change in coal strength induced by CO2 exposure were established in this work by the GMDH and GEP algorithms with acceptable accuracy. Sensitivity analysis revealed that the Spearman correlation coefficient shows the relative importance of the input parameters on the coal strength better than the Pearson correlation coefficient. Among the inputs, coal rank had the greatest influence on the coal strength (strong nonlinear relationship) based on the Spearman correlation coefficient. After that, CO2 interaction time and CO2 saturation pressure have shown relatively strong nonlinear relationships with model output, respectively. The CO2 interaction temperature had the smallest impact on coal strength alteration induced by CO2 exposure based on both Pearson and Spearman correlation coefficients. Finally, the leverage technique revealed that the laboratory database used for modeling CO2-induced strength alteration of coals was highly reliable, and the suggested GPR-Rational Quadratic model and GMDH correlation could be applied for predicting the UCS of coals exposed to CO2 with high statistical accuracy and reliability.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139391651","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}
Since the late 1980s, when the Alberta Oil Sands Technology and Research Authority Underground Test Facility project first demonstrated the feasibility of the steam-assisted gravity drainage (SAGD) technology, many commercial SAGD projects were brought online in Western Canada. Now, many of these projects have late-life SAGD wells approaching their ultimate SAGD recovery factors. Although these projects have demonstrated highly variable production performance, there is an opportunity to use the industry production data to find what they have in common and develop a normalized SAGD model. For this paper, we collected oil production history from several leading SAGD projects with late-life production in the Athabasca oil sands area and confirmed the three stages in an SAGD project lifespan: chamber rising, chamber spreading, and chamber falling stages. By normalizing the field data, all SAGD projects converged to one type curve, regardless of reservoir quality and operating conditions. Based on this observation, a new simple normalized model is derived to model the bitumen production in a typical SAGD process for Athabasca oil sands. The new model bridges the gap between the existing SAGD analytical model and conventional decline analysis and provides oil production forecasts based on the inputs for the five-component recovery factor method defined in the Canadian Oil and Gas Evaluation Handbook(Society of Petroleum Evaluation Engineers 2018). The model has been applied to one of the thermal projects to history match the field production. By running a Monte Carlo simulation, this model further demonstrates its capability to capture the uncertainty of the production forecast for the project at different stages of SAGD operation. In addition, by properly modifying the type curve of the analytical model, a similar workflow can be used to model cases with special reservoir quality or different operational limitations.
{"title":"A Simple Normalized Analytical Model for Oil Production of SAGD Process and Its Applications in Athabasca Oil Sands","authors":"Shengdong Wang","doi":"10.2118/218410-pa","DOIUrl":"https://doi.org/10.2118/218410-pa","url":null,"abstract":"\u0000 Since the late 1980s, when the Alberta Oil Sands Technology and Research Authority Underground Test Facility project first demonstrated the feasibility of the steam-assisted gravity drainage (SAGD) technology, many commercial SAGD projects were brought online in Western Canada. Now, many of these projects have late-life SAGD wells approaching their ultimate SAGD recovery factors. Although these projects have demonstrated highly variable production performance, there is an opportunity to use the industry production data to find what they have in common and develop a normalized SAGD model.\u0000 For this paper, we collected oil production history from several leading SAGD projects with late-life production in the Athabasca oil sands area and confirmed the three stages in an SAGD project lifespan: chamber rising, chamber spreading, and chamber falling stages. By normalizing the field data, all SAGD projects converged to one type curve, regardless of reservoir quality and operating conditions. Based on this observation, a new simple normalized model is derived to model the bitumen production in a typical SAGD process for Athabasca oil sands.\u0000 The new model bridges the gap between the existing SAGD analytical model and conventional decline analysis and provides oil production forecasts based on the inputs for the five-component recovery factor method defined in the Canadian Oil and Gas Evaluation Handbook(Society of Petroleum Evaluation Engineers 2018). The model has been applied to one of the thermal projects to history match the field production. By running a Monte Carlo simulation, this model further demonstrates its capability to capture the uncertainty of the production forecast for the project at different stages of SAGD operation. In addition, by properly modifying the type curve of the analytical model, a similar workflow can be used to model cases with special reservoir quality or different operational limitations.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 33","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139393065","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}
Tong Wang, Zhixue Sun, Hai Sun, Zhangxin Chen, Jun Yao
Numerical simulation of thermo-hydromechanical (THM) coupling in practical complex fractured rocks is an essential but challenging issue for the evaluation and optimization of underground energy production. In this study, we present our work on a scalable parallel compositional simulator for THM coupling, which is suitable for massive 3D polygonal fractures. In addition, we also present the improvements, parallel implementation, and optimization of an embedded discrete fracture model (EDFM). A unified cell-centered grid system based on the finite volume method (FVM) is used for all governing equations, and an extended stencil is adopted for mechanical equations to resolve the low-resolution defect of the traditional FVM. The deformation of both matrix rock and fractures is considered. A sequential fully implicit (SFI) method is adopted to solve THM coupling. This simulator is validated against three analytical solution models. Finally, we apply the simulator to two cases including a multilayered shale gas reservoir with massive natural fractures and a fractured geothermal model using CO2 as a working fluid. We also test the performance and parallel scalability on 1,024 CPU cores with up to 50 million matrix gridblocks and 5.5 million fracture gridblocks. The results show that this simulator can efficiently solve the THM coupling problem in practical massive fractures.
{"title":"Development of a Scalable Parallel Compositional Simulator for Thermo-Hydromechanical Coupling in Fractured Rocks Using an Embedded Discrete Fracture Model","authors":"Tong Wang, Zhixue Sun, Hai Sun, Zhangxin Chen, Jun Yao","doi":"10.2118/218398-pa","DOIUrl":"https://doi.org/10.2118/218398-pa","url":null,"abstract":"\u0000 Numerical simulation of thermo-hydromechanical (THM) coupling in practical complex fractured rocks is an essential but challenging issue for the evaluation and optimization of underground energy production. In this study, we present our work on a scalable parallel compositional simulator for THM coupling, which is suitable for massive 3D polygonal fractures. In addition, we also present the improvements, parallel implementation, and optimization of an embedded discrete fracture model (EDFM). A unified cell-centered grid system based on the finite volume method (FVM) is used for all governing equations, and an extended stencil is adopted for mechanical equations to resolve the low-resolution defect of the traditional FVM. The deformation of both matrix rock and fractures is considered. A sequential fully implicit (SFI) method is adopted to solve THM coupling. This simulator is validated against three analytical solution models. Finally, we apply the simulator to two cases including a multilayered shale gas reservoir with massive natural fractures and a fractured geothermal model using CO2 as a working fluid. We also test the performance and parallel scalability on 1,024 CPU cores with up to 50 million matrix gridblocks and 5.5 million fracture gridblocks. The results show that this simulator can efficiently solve the THM coupling problem in practical massive fractures.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"276 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139395278","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}
Zhaoxuan Li, Shuo Wang, Yi Pan, Rongqi Zhang, Jiajun Chen
The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures.
{"title":"Effects of Drilling Number and Distribution on Fracture Using the Pulse Plasma on Tight Sand Reservoir","authors":"Zhaoxuan Li, Shuo Wang, Yi Pan, Rongqi Zhang, Jiajun Chen","doi":"10.2118/218413-pa","DOIUrl":"https://doi.org/10.2118/218413-pa","url":null,"abstract":"\u0000 The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":" 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139391655","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}
S. Taghavi, H. Aakre, Seyed Amin Tahami, Britt M. E. Moldestad
Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.
{"title":"The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir","authors":"S. Taghavi, H. Aakre, Seyed Amin Tahami, Britt M. E. Moldestad","doi":"10.2118/218393-pa","DOIUrl":"https://doi.org/10.2118/218393-pa","url":null,"abstract":"\u0000 Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"14 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139395603","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}
Potassium chloride (KCl) is more effective in preventing salt layer dissolution than sodium chloride (NaCl) while cementing across salt formations. This paper studied the effect of KCl on the properties of cement slurry and found that KCl worsened the flowability of cement slurry. Experimental evidence confirmed that an alkaline environment promoted the dissolution of gypsum, leading to its reaction with KCl to produce syngenite. A large amount of needle-shaped syngenite caused the cement slurry to lose flowability. In addition, silica flour slurry was designed to prove the formation of syngenite and the effect of syngenite on the rheological property of the slurry. In a new way, clinker was used to prepare slurry containing KCl to prevent the generation of syngenite. The effect of KCl on the properties of clinker slurry was evaluated. The dissolution experiment of halite in clinker slurry filtrate proved that KCl had a strong ability to inhibit the dissolution of halite.
{"title":"Clinker Slurry for Cementing Across Salt Formations","authors":"Hongfei Huang, Chunyu Wang, Xiaotong Yao, Chenzi Geng","doi":"10.2118/218396-pa","DOIUrl":"https://doi.org/10.2118/218396-pa","url":null,"abstract":"\u0000 Potassium chloride (KCl) is more effective in preventing salt layer dissolution than sodium chloride (NaCl) while cementing across salt formations. This paper studied the effect of KCl on the properties of cement slurry and found that KCl worsened the flowability of cement slurry. Experimental evidence confirmed that an alkaline environment promoted the dissolution of gypsum, leading to its reaction with KCl to produce syngenite. A large amount of needle-shaped syngenite caused the cement slurry to lose flowability. In addition, silica flour slurry was designed to prove the formation of syngenite and the effect of syngenite on the rheological property of the slurry. In a new way, clinker was used to prepare slurry containing KCl to prevent the generation of syngenite. The effect of KCl on the properties of clinker slurry was evaluated. The dissolution experiment of halite in clinker slurry filtrate proved that KCl had a strong ability to inhibit the dissolution of halite.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"41 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139394487","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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