Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.04.006
Tri-axial fracturing studies were carried out to understand the impact of lateral mechanical parameters on fracture propagation from multiple in-plane perforations in horizontal wells. Additionally, the discussion covered the effects of geology, treatment, and perforation characteristics on the non-planar propagation behavior. According to experimental findings, two parallel transverse fractures can be successfully initiated from in-plane perforation clusters in the horizontal well because of the in-plane perforation, the guide nonuniform fishbone structure fracture propagation still can be exhibited. The emergence of transverse fractures and axial fractures combined as complex fractures under low horizontal principal stress difference and large pump rate conditions. The injection pressure was also investigated, and the largest breakdown pressure can be also found for samples under these conditions. The increase in perforation number or decrease in the cluster spacing could provide more chances to increase the complexity of the target stimulated zone, thus affecting the pressure fluctuation. In a contrast, the increase in fracturing fluid viscosity can reduce the multiple fracture complexity. The fracture propagation is significantly affected by the change in the rock mechanical properties. The fracture geometry in the high brittle zone seems to be complicated and tends to induce fracture reorientation from the weak-brittle zone. The stress shadow effect can be used to explain the fracture attraction, branch, connection, and repulsion in the multiple perforation clusters for the horizontal well. The increase in the rock heterogeneity can enhance the stress shadow effect, resulting in more complex fracture geometry. In addition, the variable density perforation and temporary plugging fracturing were also conducted, demonstrating higher likelihood for non-uniform multiple fracture propagation. Thus, to increase the perforation efficiency along the horizontal well, it is necessary to consider the lateral fracability of the horizontal well on target formation.
{"title":"Experimental study of hydraulic fracture propagation with multi-cluster in-plane perforations in a horizontal well","authors":"","doi":"10.1016/j.petsci.2024.04.006","DOIUrl":"10.1016/j.petsci.2024.04.006","url":null,"abstract":"<div><div>Tri-axial fracturing studies were carried out to understand the impact of lateral mechanical parameters on fracture propagation from multiple in-plane perforations in horizontal wells. Additionally, the discussion covered the effects of geology, treatment, and perforation characteristics on the non-planar propagation behavior. According to experimental findings, two parallel transverse fractures can be successfully initiated from in-plane perforation clusters in the horizontal well because of the in-plane perforation, the guide nonuniform fishbone structure fracture propagation still can be exhibited. The emergence of transverse fractures and axial fractures combined as complex fractures under low horizontal principal stress difference and large pump rate conditions. The injection pressure was also investigated, and the largest breakdown pressure can be also found for samples under these conditions. The increase in perforation number or decrease in the cluster spacing could provide more chances to increase the complexity of the target stimulated zone, thus affecting the pressure fluctuation. In a contrast, the increase in fracturing fluid viscosity can reduce the multiple fracture complexity. The fracture propagation is significantly affected by the change in the rock mechanical properties. The fracture geometry in the high brittle zone seems to be complicated and tends to induce fracture reorientation from the weak-brittle zone. The stress shadow effect can be used to explain the fracture attraction, branch, connection, and repulsion in the multiple perforation clusters for the horizontal well. The increase in the rock heterogeneity can enhance the stress shadow effect, resulting in more complex fracture geometry. In addition, the variable density perforation and temporary plugging fracturing were also conducted, demonstrating higher likelihood for non-uniform multiple fracture propagation. Thus, to increase the perforation efficiency along the horizontal well, it is necessary to consider the lateral fracability of the horizontal well on target formation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3258-3270"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140783630","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.06.016
Qing-Hai Hu , Wan Cheng , Zun-Cha Wang , Yu-Zhao Shi , Guang-Liang Jia
Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing.
{"title":"Transportation and sealing pattern of the temporary plugging ball at the spiral perforation in the horizontal well section","authors":"Qing-Hai Hu , Wan Cheng , Zun-Cha Wang , Yu-Zhao Shi , Guang-Liang Jia","doi":"10.1016/j.petsci.2024.06.016","DOIUrl":"10.1016/j.petsci.2024.06.016","url":null,"abstract":"<div><div>Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3288-3297"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141781418","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.04.018
The application of carbon dioxide (CO2) in enhanced oil recovery (EOR) has increased significantly, in which CO2 solubility in oil is a key parameter in predicting CO2 flooding performance. Hydrocarbons are the major constituents of oil, thus the focus of this work lies in investigating the solubility of CO2 in hydrocarbons. However, current experimental measurements are time-consuming, and equations of state can be computationally complex. To address these challenges, we developed an artificial intelligence-based model to predict the solubility of CO2 in hydrocarbons under varying conditions of temperature, pressure, molecular weight, and density. Using experimental data from previous studies, we trained and predicted the solubility using four machine learning models: support vector regression (SVR), extreme gradient boosting (XGBoost), random forest (RF), and multilayer perceptron (MLP). Among four models, the XGBoost model has the best predictive performance, with an R2 of 0.9838. Additionally, sensitivity analysis and evaluation of the relative impacts of each input parameter indicate that the prediction of CO2 solubility in hydrocarbons is most sensitive to pressure. Furthermore, our trained model was compared with existing models, demonstrating higher accuracy and applicability of our model. The developed machine learning-based model provides a more efficient and accurate approach for predicting CO2 solubility in hydrocarbons, which may contribute to the advancement of CO2-related applications in the petroleum industry.
{"title":"Machine learning methods for predicting CO2 solubility in hydrocarbons","authors":"","doi":"10.1016/j.petsci.2024.04.018","DOIUrl":"10.1016/j.petsci.2024.04.018","url":null,"abstract":"<div><div>The application of carbon dioxide (CO<sub>2</sub>) in enhanced oil recovery (EOR) has increased significantly, in which CO<sub>2</sub> solubility in oil is a key parameter in predicting CO<sub>2</sub> flooding performance. Hydrocarbons are the major constituents of oil, thus the focus of this work lies in investigating the solubility of CO<sub>2</sub> in hydrocarbons. However, current experimental measurements are time-consuming, and equations of state can be computationally complex. To address these challenges, we developed an artificial intelligence-based model to predict the solubility of CO<sub>2</sub> in hydrocarbons under varying conditions of temperature, pressure, molecular weight, and density. Using experimental data from previous studies, we trained and predicted the solubility using four machine learning models: support vector regression (SVR), extreme gradient boosting (XGBoost), random forest (RF), and multilayer perceptron (MLP). Among four models, the XGBoost model has the best predictive performance, with an <em>R</em><sup>2</sup> of 0.9838. Additionally, sensitivity analysis and evaluation of the relative impacts of each input parameter indicate that the prediction of CO<sub>2</sub> solubility in hydrocarbons is most sensitive to pressure. Furthermore, our trained model was compared with existing models, demonstrating higher accuracy and applicability of our model. The developed machine learning-based model provides a more efficient and accurate approach for predicting CO<sub>2</sub> solubility in hydrocarbons, which may contribute to the advancement of CO<sub>2</sub>-related applications in the petroleum industry.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3340-3349"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141026816","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.05.005
In the production of the sucker rod well, the dynamic liquid level is important for the production efficiency and safety in the lifting process. It is influenced by multi-source data which need to be combined for the dynamic liquid level real-time calculation. In this paper, the multi-source data are regarded as the different views including the load of the sucker rod and liquid in the wellbore, the image of the dynamometer card and production dynamics parameters. These views can be fused by the multi-branch neural network with special fusion layer. With this method, the features of different views can be extracted by considering the difference of the modality and physical meaning between them. Then, the extraction results which are selected by multinomial sampling can be the input of the fusion layer. During the fusion process, the availability under different views determines whether the views are fused in the fusion layer or not. In this way, not only the correlation between the views can be considered, but also the missing data can be processed automatically. The results have shown that the load and production features fusion (the method proposed in this paper) performs best with the lowest mean absolute error (MAE) 39.63 m, followed by the features concatenation with MAE 42.47 m. They both performed better than only a single view and the lower MAE of the features fusion indicates that its generalization ability is stronger. In contrast, the image feature as a single view contributes little to the accuracy improvement after fused with other views with the highest MAE. When there is data missing in some view, compared with the features concatenation, the multi-view features fusion will not result in the unavailability of a large number of samples. When the missing rate is 10%, 30%, 50% and 80%, the method proposed in this paper can reduce MAE by 5.8, 7, 9.3 and 20.3 m respectively. In general, the multi-view features fusion method proposed in this paper can improve the accuracy obviously and process the missing data effectively, which helps provide technical support for real-time monitoring of the dynamic liquid level in oil fields.
在抽油杆井的生产过程中，动态液位对生产效率和提升过程的安全性非常重要。它受到多源数据的影响，需要结合这些数据进行动态液位实时计算。在本文中，多源数据被视为不同的视图，包括抽油杆和井筒中液体的载荷、测力计卡的图像以及生产动态参数。这些视图可以通过带有特殊融合层的多分支神经网络进行融合。利用这种方法，可以通过考虑不同视图之间模态和物理意义的差异来提取它们的特征。然后，通过多叉抽样选出的提取结果可以作为融合层的输入。在融合过程中，不同视图下的可用性决定了视图是否在融合层中融合。这样，不仅可以考虑视图之间的相关性，还可以自动处理缺失数据。结果表明，负载和生产特征融合（本文提出的方法）效果最好，平均绝对误差（MAE）最低，为 39.63 m；其次是特征串联，平均绝对误差为 42.47 m。相比之下，作为单一视图的图像特征在与其他视图融合后对准确率的提高贡献不大，其 MAE 最高。当某些视图出现数据缺失时，与特征串联相比，多视图特征融合不会导致大量样本缺失。当缺失率分别为 10%、30%、50% 和 80% 时，本文提出的方法可将 MAE 分别降低 5.8、7、9.3 和 20.3 m。总的来说，本文提出的多视角特征融合方法能明显提高精度，并能有效处理缺失数据，有助于为油田动态液位的实时监测提供技术支持。
{"title":"The real-time dynamic liquid level calculation method of the sucker rod well based on multi-view features fusion","authors":"","doi":"10.1016/j.petsci.2024.05.005","DOIUrl":"10.1016/j.petsci.2024.05.005","url":null,"abstract":"<div><div>In the production of the sucker rod well, the dynamic liquid level is important for the production efficiency and safety in the lifting process. It is influenced by multi-source data which need to be combined for the dynamic liquid level real-time calculation. In this paper, the multi-source data are regarded as the different views including the load of the sucker rod and liquid in the wellbore, the image of the dynamometer card and production dynamics parameters. These views can be fused by the multi-branch neural network with special fusion layer. With this method, the features of different views can be extracted by considering the difference of the modality and physical meaning between them. Then, the extraction results which are selected by multinomial sampling can be the input of the fusion layer. During the fusion process, the availability under different views determines whether the views are fused in the fusion layer or not. In this way, not only the correlation between the views can be considered, but also the missing data can be processed automatically. The results have shown that the load and production features fusion (the method proposed in this paper) performs best with the lowest mean absolute error (MAE) 39.63 m, followed by the features concatenation with MAE 42.47 m. They both performed better than only a single view and the lower MAE of the features fusion indicates that its generalization ability is stronger. In contrast, the image feature as a single view contributes little to the accuracy improvement after fused with other views with the highest MAE. When there is data missing in some view, compared with the features concatenation, the multi-view features fusion will not result in the unavailability of a large number of samples. When the missing rate is 10%, 30%, 50% and 80%, the method proposed in this paper can reduce MAE by 5.8, 7, 9.3 and 20.3 m respectively. In general, the multi-view features fusion method proposed in this paper can improve the accuracy obviously and process the missing data effectively, which helps provide technical support for real-time monitoring of the dynamic liquid level in oil fields.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3575-3586"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141028070","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.05.003
Pressure-preserved coring is an effective means to develop deep resources. However, due to the complexity of existing pressure-preserved technology, the average success rate of pressure-preserved coring is low. In response, a novel in situ magnetically controlled self-sealing pressure-preserved coring technology for deep reserves has been proposed and validated. This innovative technology distinguishes itself from conventional methods by employing noncontact forces to replace traditional pre-tensioning mechanisms, thereby enhancing the mechanical design of pressure-preserved coring equipment and significantly boosting the fault tolerance of the technology. Here, we report on the design, theoretical calculations, experimental validation, and industrial testing of this technology. Through theoretical and simulation calculations, the self-sealing composite magnetic field of the pressure controller was optimized. The initial pre-tensioning force of the optimal magnetic field was 13.05 N. The reliability of the magnetically controlled self-sealing pressure-preserved coring technology was verified using a self-developed self-sealing pressure performance testing platform, confirming the accuracy of the composite magnetic field calculation theory. Subsequently, a magnetically controlled self-triggering pressure-preserved coring device was designed. Field pressure-preserved coring was then conducted, preliminarily verifying the technology's effective self-sealing performance in industrial applications. Furthermore, the technology was analyzed and verified to be adaptable to complex reservoir environments with pressures up to 30 MPa, temperatures up to 80 °C, and pH values ranging from 1 to 14. These research results provide technical support for multidirectional pressure-preserved coring, thus paving a new technical route for deep energy exploration through coring.
{"title":"Magnetically controlled self-sealing pressure-preserved coring technology","authors":"","doi":"10.1016/j.petsci.2024.05.003","DOIUrl":"10.1016/j.petsci.2024.05.003","url":null,"abstract":"<div><div>Pressure-preserved coring is an effective means to develop deep resources. However, due to the complexity of existing pressure-preserved technology, the average success rate of pressure-preserved coring is low. In response, a novel in situ magnetically controlled self-sealing pressure-preserved coring technology for deep reserves has been proposed and validated. This innovative technology distinguishes itself from conventional methods by employing noncontact forces to replace traditional pre-tensioning mechanisms, thereby enhancing the mechanical design of pressure-preserved coring equipment and significantly boosting the fault tolerance of the technology. Here, we report on the design, theoretical calculations, experimental validation, and industrial testing of this technology. Through theoretical and simulation calculations, the self-sealing composite magnetic field of the pressure controller was optimized. The initial pre-tensioning force of the optimal magnetic field was 13.05 N. The reliability of the magnetically controlled self-sealing pressure-preserved coring technology was verified using a self-developed self-sealing pressure performance testing platform, confirming the accuracy of the composite magnetic field calculation theory. Subsequently, a magnetically controlled self-triggering pressure-preserved coring device was designed. Field pressure-preserved coring was then conducted, preliminarily verifying the technology's effective self-sealing performance in industrial applications. Furthermore, the technology was analyzed and verified to be adaptable to complex reservoir environments with pressures up to 30 MPa, temperatures up to 80 °C, and pH values ranging from 1 to 14. These research results provide technical support for multidirectional pressure-preserved coring, thus paving a new technical route for deep energy exploration through coring.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3464-3481"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141033115","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.05.010
Seismic wave propagation in fluid-solid coupled media is currently a popular topic. However, traditional wave equation-based simulation methods have to consider complex boundary conditions at the fluid-solid interface. To address this challenge, we propose a novel numerical scheme that integrates the lattice Boltzmann method (LBM) and lattice spring model (LSM). In this scheme, LBM simulates viscoacoustic wave propagation in the fluid area and LSM simulates elastic wave propagation in the solid area. We also introduce three different LBM-LSM coupling strategies, a standard bounce back scheme, a specular reflection scheme, and a hybrid scheme, to describe wave propagation across fluid-solid boundaries. To demonstrate the accuracy of these LBM-LSM coupling schemes, we simulate wave propagation in a two-layer model containing a fluid-solid interface. We place excitation sources in the fluid layer and the solid layer respectively, to observe the wave phenomena when seismic waves propagate to interface from different sides. The simulated results by LBM-LSM are compared with the reference wavefields obtained by the finite difference method (FDM) and the analytical solution (ANA). Our LBM-LSM coupling scheme was verified effective, as the relative errors between the LBM-LSM solutions and reference solutions were within an acceptable range, sometimes around 1.00%. The coupled LBM-LSM scheme is further used to model seismic wavefields across a more realistic rugged seabed, which reveals the potential applications of the coupled LBM-LSM scheme in marine seismic imaging techniques, such as reverse-time migration and full-waveform inversion. The method also has potential applications in simulating wave propagation in complex two- and multi-phase media.
{"title":"Wave propagation across fluid-solid interfaces with LBM-LSM coupling schemes","authors":"","doi":"10.1016/j.petsci.2024.05.010","DOIUrl":"10.1016/j.petsci.2024.05.010","url":null,"abstract":"<div><div>Seismic wave propagation in fluid-solid coupled media is currently a popular topic. However, traditional wave equation-based simulation methods have to consider complex boundary conditions at the fluid-solid interface. To address this challenge, we propose a novel numerical scheme that integrates the lattice Boltzmann method (LBM) and lattice spring model (LSM). In this scheme, LBM simulates viscoacoustic wave propagation in the fluid area and LSM simulates elastic wave propagation in the solid area. We also introduce three different LBM-LSM coupling strategies, a standard bounce back scheme, a specular reflection scheme, and a hybrid scheme, to describe wave propagation across fluid-solid boundaries. To demonstrate the accuracy of these LBM-LSM coupling schemes, we simulate wave propagation in a two-layer model containing a fluid-solid interface. We place excitation sources in the fluid layer and the solid layer respectively, to observe the wave phenomena when seismic waves propagate to interface from different sides. The simulated results by LBM-LSM are compared with the reference wavefields obtained by the finite difference method (FDM) and the analytical solution (ANA). Our LBM-LSM coupling scheme was verified effective, as the relative errors between the LBM-LSM solutions and reference solutions were within an acceptable range, sometimes around 1.00%. The coupled LBM-LSM scheme is further used to model seismic wavefields across a more realistic rugged seabed, which reveals the potential applications of the coupled LBM-LSM scheme in marine seismic imaging techniques, such as reverse-time migration and full-waveform inversion. The method also has potential applications in simulating wave propagation in complex two- and multi-phase media.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3125-3141"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141137970","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.06.003
The gelation of crude oil with high wax and asphaltene content at low temperatures often results in the block of transportation pipeline in Africa. In recent years, it was reported that surface hydrophobic-modified nanoparticles have important applications in crude oil flow modification. In this work, four kinds of core-shell hybride nanoparticles by grafting poly (octadecyl, docosyl acrylate) and poly (acrylate-α-olefin) onto the surface of nano-sized SiO2 were synthesized by grafting polymerization method. The chemical structure of nanoparticles was analyzed by Fourier transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM) and thermogravimetric analysis (TGA). The rheological behaviors of crude oil and precipitation of asphaltenes in the presence of nanoparticles were studied by measuring the viscose-temperature relationship curve, the cumulative wax precipitation amount, and morphology of waxes and asphaltenes. The results indicate that the docosyl polyacrylate@SiO2 nanoparticle (PDA@SiO2) can reduce the cumulative wax precipitation amount of crude oil by 72.8%, decline the viscosity of crude oil by 85.6% at 20 °C, reduce the average size of wax crystals by 89.7%, and inhibit the agglomeration of asphaltene by 74.8%. Therefore, the nanoparticles not only adjust the crystalline behaviors of waxes, but also inhibit the agglomeration of asphaltenes. Apparently, core-shell hybride nanoparticles provides more heterogeneous nucleation sites for the crystallization of wax molecules, thus inhibiting the formation of three-dimensional network structure. The core-shell polymer@SiO2 hybride nanoparticles are one of promising additives for inhibiting crystallization of waxes and agglomeration of asphaltenes in crude oil.
{"title":"Inhibition of wax crystallization and asphaltene agglomeration by core-shell polymer@SiO2 hybride nano-particles","authors":"","doi":"10.1016/j.petsci.2024.06.003","DOIUrl":"10.1016/j.petsci.2024.06.003","url":null,"abstract":"<div><div>The gelation of crude oil with high wax and asphaltene content at low temperatures often results in the block of transportation pipeline in Africa. In recent years, it was reported that surface hydrophobic-modified nanoparticles have important applications in crude oil flow modification. In this work, four kinds of core-shell hybride nanoparticles by grafting poly (octadecyl, docosyl acrylate) and poly (acrylate-α-olefin) onto the surface of nano-sized SiO<sub>2</sub> were synthesized by grafting polymerization method. The chemical structure of nanoparticles was analyzed by Fourier transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM) and thermogravimetric analysis (TGA). The rheological behaviors of crude oil and precipitation of asphaltenes in the presence of nanoparticles were studied by measuring the viscose-temperature relationship curve, the cumulative wax precipitation amount, and morphology of waxes and asphaltenes. The results indicate that the docosyl polyacrylate@SiO<sub>2</sub> nanoparticle (PDA@SiO<sub>2</sub>) can reduce the cumulative wax precipitation amount of crude oil by 72.8%, decline the viscosity of crude oil by 85.6% at 20 °C, reduce the average size of wax crystals by 89.7%, and inhibit the agglomeration of asphaltene by 74.8%. Therefore, the nanoparticles not only adjust the crystalline behaviors of waxes, but also inhibit the agglomeration of asphaltenes. Apparently, core-shell hybride nanoparticles provides more heterogeneous nucleation sites for the crystallization of wax molecules, thus inhibiting the formation of three-dimensional network structure. The core-shell polymer@SiO<sub>2</sub> hybride nanoparticles are one of promising additives for inhibiting crystallization of waxes and agglomeration of asphaltenes in crude oil.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3621-3629"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141400180","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.03.024
Currently, horizontal well fracturing is indispensable for shale gas development. Due to the variable reservoir formation morphology, the drilling trajectory often deviates from the high-quality reservoir, which increases the risk of fracturing. Accurately recognizing low-amplitude structures plays a crucial role in guiding horizontal wells. However, existing methods have low recognition accuracy, and are difficult to meet actual production demand. In order to improve the drilling encounter rate of high-quality reservoirs, we propose a method for fine recognition of low-amplitude structures based on the non-subsampled contourlet transform (NSCT). Firstly, the seismic structural data are analyzed at multiple scales and directions using the NSCT and decomposed into low-frequency and high-frequency structural components. Then, the signal of each component is reconstructed to eliminate the low-frequency background of the structure, highlight the structure and texture information, and recognize the low-amplitude structure from it. Finally, we combined the drilled horizontal wells to verify the low-amplitude structural recognition results. Taking a study area in the west Sichuan Basin block as an example, we demonstrate the fine identification of low-amplitude structures based on NSCT. By combining the variation characteristics of logging curves, such as organic carbon content (TOC), natural gamma value (GR), etc., the real structure type is verified and determined, and the false structures in the recognition results are checked. The proposed method can provide reliable information on low-amplitude structures for optimizing the trajectory of horizontal wells. Compared with identification methods based on traditional wavelet transform and curvelet transform, NSCT enhances the local features of low-amplitude structures and achieves finer mapping of low-amplitude structures, showing promise for application.
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Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.04.016
<div><div>Lost circulation, a recurring peril during drilling operations, entails substantial loss of drilling fluid and dire consequences upon its infiltration into the formation. As drilling depth escalates, the formation temperature and pressure intensify, imposing exacting demands on plug materials. In this study, a kind of controllable curing resin with dense cross-network structure was prepared by the method of solution stepwise ring-opening polymerization. The resin plugging material investigated in this study is a continuous phase material that offers effortless injection, robust filling capabilities, exceptional retention, and underground curing or crosslinking with high strength. Its versatility is not constrained by fracture-cavity lose channels, making it suitable for fulfilling the essential needs of various fracture-cavity combinations when plugging fracture-cavity carbonate rocks. Notably, the curing duration can be fine-tuned within the span of 3–7 h, catering to the plugging of drilling fluid losing of diverse fracture dimensions. Experimental scrutiny encompassed the rheological properties and curing behavior of the resin plugging system, unraveling the intricacies of the curing process and establishing a cogent kinetic model. The experimental results show that the urea-formaldehyde resin plugging material has a tight chain or network structure. When the concentration of the urea-formaldehyde resin plugging system solution remains below 30%, the viscosity clocks in at a meager 10 mPa·s. Optimum curing transpires at 60 °C, showcasing impressive resilience to saline conditions. Remarkably, when immersed in a composite saltwater environment containing 50000 mg/L NaCl and 100000 mg/L CaCl<sub>2</sub>, the urea-formaldehyde resin consolidates into an even more compact network structure, culminating in an outstanding compressive strength of 41.5 MPa. Through resolving the correlation between conversion and the apparent activation energy of the non-isothermal DSC curing reaction parameters, the study attests to the fulfillment of the kinetic equation for the urea-formaldehyde resin plugging system. This discerning analysis illuminates the nuanced shifts in the microscopic reaction mechanism of the urea-formaldehyde resin plugging system. Furthermore, the pressure bearing plugging capacity of the resin plugging system for fractures of different sizes is also studied. It is found that the resin plugging system can effectively resident in parallel and wedge-shaped fractures of different sizes, and form high-strength consolidation under certain temperature conditions. The maximum plugging pressure of resin plugging system for parallel fractures with outlet size 3 mm can reach 9.92 MPa, and the maximum plugging pressure for wedge-shaped fractures with outlet size 5 mm can reach 9.90 MPa. Consequently, the exploration and application of urea-formaldehyde resin plugging material precipitate a paradigm shift, proffering novel concepts and meth
{"title":"Curing kinetics and plugging mechanism of high strength curable resin plugging material","authors":"","doi":"10.1016/j.petsci.2024.04.016","DOIUrl":"10.1016/j.petsci.2024.04.016","url":null,"abstract":"<div><div>Lost circulation, a recurring peril during drilling operations, entails substantial loss of drilling fluid and dire consequences upon its infiltration into the formation. As drilling depth escalates, the formation temperature and pressure intensify, imposing exacting demands on plug materials. In this study, a kind of controllable curing resin with dense cross-network structure was prepared by the method of solution stepwise ring-opening polymerization. The resin plugging material investigated in this study is a continuous phase material that offers effortless injection, robust filling capabilities, exceptional retention, and underground curing or crosslinking with high strength. Its versatility is not constrained by fracture-cavity lose channels, making it suitable for fulfilling the essential needs of various fracture-cavity combinations when plugging fracture-cavity carbonate rocks. Notably, the curing duration can be fine-tuned within the span of 3–7 h, catering to the plugging of drilling fluid losing of diverse fracture dimensions. Experimental scrutiny encompassed the rheological properties and curing behavior of the resin plugging system, unraveling the intricacies of the curing process and establishing a cogent kinetic model. The experimental results show that the urea-formaldehyde resin plugging material has a tight chain or network structure. When the concentration of the urea-formaldehyde resin plugging system solution remains below 30%, the viscosity clocks in at a meager 10 mPa·s. Optimum curing transpires at 60 °C, showcasing impressive resilience to saline conditions. Remarkably, when immersed in a composite saltwater environment containing 50000 mg/L NaCl and 100000 mg/L CaCl<sub>2</sub>, the urea-formaldehyde resin consolidates into an even more compact network structure, culminating in an outstanding compressive strength of 41.5 MPa. Through resolving the correlation between conversion and the apparent activation energy of the non-isothermal DSC curing reaction parameters, the study attests to the fulfillment of the kinetic equation for the urea-formaldehyde resin plugging system. This discerning analysis illuminates the nuanced shifts in the microscopic reaction mechanism of the urea-formaldehyde resin plugging system. Furthermore, the pressure bearing plugging capacity of the resin plugging system for fractures of different sizes is also studied. It is found that the resin plugging system can effectively resident in parallel and wedge-shaped fractures of different sizes, and form high-strength consolidation under certain temperature conditions. The maximum plugging pressure of resin plugging system for parallel fractures with outlet size 3 mm can reach 9.92 MPa, and the maximum plugging pressure for wedge-shaped fractures with outlet size 5 mm can reach 9.90 MPa. Consequently, the exploration and application of urea-formaldehyde resin plugging material precipitate a paradigm shift, proffering novel concepts and meth","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3446-3463"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141037636","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.petsci.2024.04.014
Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage.
In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.
The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage.
原位燃烧的实验室建模对于了解热力强化采油（EOR）现场试验的潜在成功率至关重要，也是将该技术推广到现场应用的重要前提。高达 480 °C 的燃烧温度会引起岩石的显著岩石物理变化，这也是热能强化采油（EOR）项目中经常被忽视的一个方面。在这项研究中，我们放弃了使用破碎岩芯的传统燃烧实验，转而使用固结样本分析热效应对碳酸盐岩储层性质的影响。这项技术保持了固有的孔隙度和渗透率，揭示了燃烧对孔隙度和矿物学变化的影响，并对燃烧前后的这些特性进行了对比分析。我们利用低场核磁共振、X 射线显微计算机断层扫描和低温氮吸附来描述孔隙度和孔隙几何演变的特征。扫描电子显微镜和 X 射线衍射分析了岩石的矿物成分和晶粒孔隙尺度的变化。分析表明，碳酸盐岩的孔隙度、孔隙大小和矿物变化显著增加，并从混湿状态过渡到强水湿状态。岩石样本的总孔隙率平均增加了 15%-20%，并形成了 1-30 μm 大小的新孔隙。高温暴露导致方解石和白云石分解、方解石溶解并形成新的矿物--无水石膏和萤石。微孔的增加和向强水湿岩石状态的转变改善了毛细管和残余二氧化碳捕集的前景，并提高了捕集能力。因此，与使用破碎岩心进行的试验相比，这些研究结果突出了在固结岩石上进行实验室原位燃烧建模的重要性，并表明枯竭燃烧激发储层可能被证明是可行的二氧化碳封存候选方案。
{"title":"Exploring in-situ combustion effects on reservoir properties of heavy oil carbonate reservoir","authors":"","doi":"10.1016/j.petsci.2024.04.014","DOIUrl":"10.1016/j.petsci.2024.04.014","url":null,"abstract":"<div><div>Laboratory modeling of <em>in-situ</em> combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO<sub>2</sub> storage.</div><div>In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.</div><div>The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO<sub>2</sub> trapping with greater capacity. Consequently, these findings highlight the importance of laboratory <em>in-situ</em> combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO<sub>2</sub> storage.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 5","pages":"Pages 3363-3378"},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141041020","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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