The importance of wettability in reservoir evaluation and dynamics in shale is gaining increasing attention. Wettability is also a key consideration in the strategy development of enhanced oil recovery (EOR) in unconventional reservoirs. However, the determination of shale wettability is often elusive, and an understanding still remains incomplete. Several commonly applied assumptions and methods for evaluating shale wettability are considered inaccurate or problematic. In this work, important clarifications about shale wettability and the methods of measurement or evaluation are made. Wettability is studied for six shale samples from Eagle Ford and Wolfcamp Shale formations with increasing thermal maturity using an integrated imbibition and imaging method. Wettability was evaluated based on the results of water-oil displacement via spontaneous imbibition and the dominant pore type in the sample. Wettability of the samples is ranged from strong water-wet (SW) to oil-wet and has a general trend of becoming less water-wet (or more oil-wet) with increasing thermal maturity (Ro value from ~0.45 to 1.4%). A new hypothesis on shale wettability transformation from the original water-wet status is proposed based on the results. This new hypothesis emphasizes the evaluation of shale wettability under a dynamic context of oil-water displacement and oil aging history, and shale wettability is a result of oil-water-rock interaction through the geological time frame. Enhanced oil mobility caused by increasing thermal maturity is the main drive of oil imbibition, whereas pore type and pore size also play an important role in oil-water displacement and consequently wettability transformation. The ease of wettability transformation of the pore system in shale is in the order of calcite > quartz, dolomite >> clay. Pores with mixed boundaries of different minerals fall in between. Other geological factors [e.g., total organic carbon (TOC) and pore pressure] also affect oil imbibition and thus wettability. Important implications of shale wettability on water and oil saturation and on improved oil recovery are also discussed.
{"title":"Shale Wettability: Untangling the Elusive Property with an Integrated Imbibition and Imaging Technique and a New Hypothetical Theory","authors":"S. Peng, P. Shevchenko, L. Ko","doi":"10.2118/212276-pa","DOIUrl":"https://doi.org/10.2118/212276-pa","url":null,"abstract":"\u0000 The importance of wettability in reservoir evaluation and dynamics in shale is gaining increasing attention. Wettability is also a key consideration in the strategy development of enhanced oil recovery (EOR) in unconventional reservoirs. However, the determination of shale wettability is often elusive, and an understanding still remains incomplete. Several commonly applied assumptions and methods for evaluating shale wettability are considered inaccurate or problematic. In this work, important clarifications about shale wettability and the methods of measurement or evaluation are made. Wettability is studied for six shale samples from Eagle Ford and Wolfcamp Shale formations with increasing thermal maturity using an integrated imbibition and imaging method. Wettability was evaluated based on the results of water-oil displacement via spontaneous imbibition and the dominant pore type in the sample. Wettability of the samples is ranged from strong water-wet (SW) to oil-wet and has a general trend of becoming less water-wet (or more oil-wet) with increasing thermal maturity (Ro value from ~0.45 to 1.4%). A new hypothesis on shale wettability transformation from the original water-wet status is proposed based on the results. This new hypothesis emphasizes the evaluation of shale wettability under a dynamic context of oil-water displacement and oil aging history, and shale wettability is a result of oil-water-rock interaction through the geological time frame. Enhanced oil mobility caused by increasing thermal maturity is the main drive of oil imbibition, whereas pore type and pore size also play an important role in oil-water displacement and consequently wettability transformation. The ease of wettability transformation of the pore system in shale is in the order of calcite > quartz, dolomite >> clay. Pores with mixed boundaries of different minerals fall in between. Other geological factors [e.g., total organic carbon (TOC) and pore pressure] also affect oil imbibition and thus wettability. Important implications of shale wettability on water and oil saturation and on improved oil recovery are also discussed.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"53 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81207972","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Mukhametdinova, T. Karamov, E. Popov, A. Burukhin, E. Kozlova, G. Usachev, A. Cheremisin
This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.
{"title":"Reservoir Properties Alteration in Carbonate Rocks after In-Situ Combustion","authors":"A. Mukhametdinova, T. Karamov, E. Popov, A. Burukhin, E. Kozlova, G. Usachev, A. Cheremisin","doi":"10.2118/212281-pa","DOIUrl":"https://doi.org/10.2118/212281-pa","url":null,"abstract":"\u0000 This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"17 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84661187","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In-situ combustion (ISC) is a promising thermal enhanced oil recovery method with benefits for deep reservoirs, potentially lesser energy requirements as compared to steam injection, and low opportunity cost. Although successful ISC projects have been developed all over the world, challenges still exist including difficulties in monitoring combustion-front progress in the field, describing multiscale physical processes, characterizing crude oil kinetics fully, and simulating ISC at field scale. This work predicts combustion front propagation and the effect of thermally induced stress at the scale of an ISC pilot project. Reservoir deformation was characterized by a geomechanical model to investigate the correlation of combustion front progress with reservoir and surface deformation. We upscaled the reaction kinetics directly from combustion tube experiments and calibrated the laboratory-scale model compared with experimental measurements. We then upscaled numerical simulation to a 3D geometry incorporating a geomechanical model. The change in scale is significant as the combustion tube is 6.56 ft (2 m) in length, whereas the dimensions of the 3D model are 1,440 ft by 1,440 ft (439 m) by 1,400 ft (427 m). The elastic properties were defined by Young’s modulus and Poisson’s ratio, whereas the plastic properties were defined by a Mohr-Coulomb model. A sensitivity study examined the reliability of the model, showing the reaction progress and geomechanical responses were not significantly impacted by gridblock dimensions and reservoir heterogeneity. Finally, a field-scale model was developed covering an area of 5,960 ft (1817 m) by 4,200 ft (1280 m). We observed successful ISC simulation including ignition as air injection started. The temperature increased immediately to more than 800°C (1,400°F) based on the chemical kinetics implemented. The temperature history indicated that the combustion front propagated from the injection well into the reservoir with an average velocity of 0.16 ft/D (0.049 m/d). A surface deformation map correlated with the progress of ISC in the subsurface. Land surface uplift because of ISC ranges from 0.1 ft (0.03 m) to several feet, depending on the rock properties and subsurface events. This proof-of-concept model indicated strong potential to detect the surface movement using interferometric synthetic aperture radar (InSAR) and/or tiltmeters to monitor dynamically combustion front positions in subsurface.
{"title":"Progress Toward Pilot-Scale Simulation of In-Situ Combustion Incorporating Geomechanics","authors":"Y. Li, E. Manrique, A. Kovscek","doi":"10.2118/212266-pa","DOIUrl":"https://doi.org/10.2118/212266-pa","url":null,"abstract":"\u0000 In-situ combustion (ISC) is a promising thermal enhanced oil recovery method with benefits for deep reservoirs, potentially lesser energy requirements as compared to steam injection, and low opportunity cost. Although successful ISC projects have been developed all over the world, challenges still exist including difficulties in monitoring combustion-front progress in the field, describing multiscale physical processes, characterizing crude oil kinetics fully, and simulating ISC at field scale. This work predicts combustion front propagation and the effect of thermally induced stress at the scale of an ISC pilot project. Reservoir deformation was characterized by a geomechanical model to investigate the correlation of combustion front progress with reservoir and surface deformation. We upscaled the reaction kinetics directly from combustion tube experiments and calibrated the laboratory-scale model compared with experimental measurements. We then upscaled numerical simulation to a 3D geometry incorporating a geomechanical model. The change in scale is significant as the combustion tube is 6.56 ft (2 m) in length, whereas the dimensions of the 3D model are 1,440 ft by 1,440 ft (439 m) by 1,400 ft (427 m). The elastic properties were defined by Young’s modulus and Poisson’s ratio, whereas the plastic properties were defined by a Mohr-Coulomb model. A sensitivity study examined the reliability of the model, showing the reaction progress and geomechanical responses were not significantly impacted by gridblock dimensions and reservoir heterogeneity. Finally, a field-scale model was developed covering an area of 5,960 ft (1817 m) by 4,200 ft (1280 m). We observed successful ISC simulation including ignition as air injection started. The temperature increased immediately to more than 800°C (1,400°F) based on the chemical kinetics implemented. The temperature history indicated that the combustion front propagated from the injection well into the reservoir with an average velocity of 0.16 ft/D (0.049 m/d). A surface deformation map correlated with the progress of ISC in the subsurface. Land surface uplift because of ISC ranges from 0.1 ft (0.03 m) to several feet, depending on the rock properties and subsurface events. This proof-of-concept model indicated strong potential to detect the surface movement using interferometric synthetic aperture radar (InSAR) and/or tiltmeters to monitor dynamically combustion front positions in subsurface.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"118 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77394519","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Polymer flooding is one of the most commonly used chemical enhanced oil recovery (EOR) methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers in porous media is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. This proposed model was developed and validated using 30 coreflooding tests obtained from the literature and further verified against a few existing viscoelastic models. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscoelastic model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Moreover, the fitting parameters used in the model were correlated to rock and polymer properties using machine learning technique, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Furthermore, the E-UVM was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It is worth mentioning that the irreversible viscosity drop for mechanical degradation regime was captured during implementing our model in the simulator. It was found that implementing the E-UVM in MRST for polymer non-Newtonian behavior might be more practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator showed that the latter model could yield more reliable oil recovery predictions as the apparent viscosity is modeled properly in the mechanical degradation regime, unlike UVM or Carreau models. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature. Furthermore, the need to conduct an extensive coreflooding experiment can be reduced by virtue of developed correlations that may be used to estimate model fitting parameters accounting for shear-thickening and mechanical degradation.
{"title":"An Extended Unified Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates","authors":"Mursal Zeynalli, E. Al-Shalabi, W. Alameri","doi":"10.2118/206010-pa","DOIUrl":"https://doi.org/10.2118/206010-pa","url":null,"abstract":"\u0000 Polymer flooding is one of the most commonly used chemical enhanced oil recovery (EOR) methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers in porous media is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. This proposed model was developed and validated using 30 coreflooding tests obtained from the literature and further verified against a few existing viscoelastic models.\u0000 The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscoelastic model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Moreover, the fitting parameters used in the model were correlated to rock and polymer properties using machine learning technique, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Furthermore, the E-UVM was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It is worth mentioning that the irreversible viscosity drop for mechanical degradation regime was captured during implementing our model in the simulator. It was found that implementing the E-UVM in MRST for polymer non-Newtonian behavior might be more practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator showed that the latter model could yield more reliable oil recovery predictions as the apparent viscosity is modeled properly in the mechanical degradation regime, unlike UVM or Carreau models.\u0000 This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature. Furthermore, the need to conduct an extensive coreflooding experiment can be reduced by virtue of developed correlations that may be used to estimate model fitting parameters accounting for shear-thickening and mechanical degradation.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"30 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85761656","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sedimentary rocks display complex spatial distribution of both pore space and solid components, impacting the directional dependence of physical phenomena such as electrical conduction, fluid flow, heat transfer, and molecular diffusion. The complexity of the pore space is often quantified by the concept of tortuosity, which measures the sinuosity of the connecting paths in the pore space. Tortuosity is an important quantity in formation evaluation as it impacts petrophysical properties such as permeability and formation factor. However, the existence of various techniques can lead to nonuniqueness in assessment of tortuosity. Furthermore, spatial variation of the solid components of the rocks occurring at the core-scale domain reflected in the connectivity and distribution of the minerals is typically not quantified. The objectives of this paper are (a) to quantify tortuosity and tortuosity anisotropy of porous media through estimation of electrical, diffusional, hydraulic, and geometrical tortuosity at the pore scale and core scale and (b) to compare electrical, diffusional, hydraulic, and geometrical tortuosity. We estimate tortuosity in the pore space of microcomputed tomography (micro-CT) scan images and in the most connected and abundant solid phase of whole-core CT scan images. We conduct numerical simulations of electric potential distribution, diffusion, and fluid flow and velocity distribution to estimate electrical, diffusional, and hydraulic tortuosity, respectively. To calculate geometrical tortuosity, we use the segmented pore space from micro-CT scan images to extract a pore network model and compute the shortest path of all opposing pores of the samples. Finally, tortuosity values obtained with each technique are used to assess the anisotropy of the samples. We applied the documented workflow to core- and pore-scale images. The CT scan images in the core-scale domain belong to a siliciclastic formation. Micro-CT scan images in the pore-scale domain were obtained from Berea Sandstone, Austin Chalk, and Estaillades limestone formations. We observed differences in estimates of direction-dependent electrical, diffusional, hydraulic, and geometrical tortuosity for both types of images. The highest numerical differences were observed when comparing streamline electrical and hydraulic tortuosity with diffusional tortuosity. The observed differences were significant in anisotropic samples. Differences in tortuosity estimates can impact the outcomes of rock physics models for which tortuosity is an input. The documented comparison provides insight in the selection of techniques for tortuosity estimation. Use of core-scale image data provides semicontinuous estimates of tortuosity and tortuosity anisotropy, which are typically not attainable using pore-scale images. Additionally, the semicontinuous tortuosity anisotropy estimates from whole-core CT scan images provide a tool for selection of best locations to take core plugs.
{"title":"Electrical, Diffusional, Hydraulic, and Geometrical Tortuosity Anisotropy Quantification Using 3D Computed Tomography Scan Image Data","authors":"Andres Gonzalez, Z. Heidari, O. Lopez","doi":"10.2118/206109-pa","DOIUrl":"https://doi.org/10.2118/206109-pa","url":null,"abstract":"\u0000 Sedimentary rocks display complex spatial distribution of both pore space and solid components, impacting the directional dependence of physical phenomena such as electrical conduction, fluid flow, heat transfer, and molecular diffusion. The complexity of the pore space is often quantified by the concept of tortuosity, which measures the sinuosity of the connecting paths in the pore space. Tortuosity is an important quantity in formation evaluation as it impacts petrophysical properties such as permeability and formation factor. However, the existence of various techniques can lead to nonuniqueness in assessment of tortuosity. Furthermore, spatial variation of the solid components of the rocks occurring at the core-scale domain reflected in the connectivity and distribution of the minerals is typically not quantified. The objectives of this paper are (a) to quantify tortuosity and tortuosity anisotropy of porous media through estimation of electrical, diffusional, hydraulic, and geometrical tortuosity at the pore scale and core scale and (b) to compare electrical, diffusional, hydraulic, and geometrical tortuosity.\u0000 We estimate tortuosity in the pore space of microcomputed tomography (micro-CT) scan images and in the most connected and abundant solid phase of whole-core CT scan images. We conduct numerical simulations of electric potential distribution, diffusion, and fluid flow and velocity distribution to estimate electrical, diffusional, and hydraulic tortuosity, respectively. To calculate geometrical tortuosity, we use the segmented pore space from micro-CT scan images to extract a pore network model and compute the shortest path of all opposing pores of the samples. Finally, tortuosity values obtained with each technique are used to assess the anisotropy of the samples.\u0000 We applied the documented workflow to core- and pore-scale images. The CT scan images in the core-scale domain belong to a siliciclastic formation. Micro-CT scan images in the pore-scale domain were obtained from Berea Sandstone, Austin Chalk, and Estaillades limestone formations. We observed differences in estimates of direction-dependent electrical, diffusional, hydraulic, and geometrical tortuosity for both types of images. The highest numerical differences were observed when comparing streamline electrical and hydraulic tortuosity with diffusional tortuosity. The observed differences were significant in anisotropic samples. Differences in tortuosity estimates can impact the outcomes of rock physics models for which tortuosity is an input. The documented comparison provides insight in the selection of techniques for tortuosity estimation. Use of core-scale image data provides semicontinuous estimates of tortuosity and tortuosity anisotropy, which are typically not attainable using pore-scale images. Additionally, the semicontinuous tortuosity anisotropy estimates from whole-core CT scan images provide a tool for selection of best locations to take core plugs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"128 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80242689","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the development of catanionic surfactants composed of cationic and anionic surfactants to make them high-performance products for chemical flooding in high-temperature and high-salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing oppositely charged anionic surfactants and cationic surfactants (CASs), which results in significant synergistic effects in interfacial properties due to electrostatic attraction to improve oil production at the given harsh conditions. The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high-salinity brine at 90°C. Comprehensive performance of the catanionic surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95°C. The coreflooding displacement experiments were performed using carbonate core plugs at 95°C to evaluate the potential of the optimal catanionic surfactant in improving oil recovery. Three catanionic surfactants with good compatibility were developed in this study. It appeared that the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was between 10−1 and 100 mN/m, a significant IFT reduction in the magnitude of 10−2 to 10−3 mN/m was observed by mixing the selected anionic surfactants and CASs. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the effectiveness of the catanionic surfactant. In microemulsion phase behavior studies, the developed catanionic surfactant solution in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorption quantities of the catanionic surfactants were lower than the values of the individual surfactants. All these indicated the feasibility of catanionic surfactants for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil recovery improvement beyond waterflooding. This work provides an efficient way to get surfactant formulations by mixing oppositely charged surfactants to obtain high performance in improving oil production under harsh conditions.
{"title":"Catanionic Surfactants for Improving Oil Production in Carbonate Reservoirs","authors":"Limin Xu, M. Han, D. Cao, A. Fuseni","doi":"10.2118/200182-pa","DOIUrl":"https://doi.org/10.2118/200182-pa","url":null,"abstract":"\u0000 This paper presents the development of catanionic surfactants composed of cationic and anionic surfactants to make them high-performance products for chemical flooding in high-temperature and high-salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing oppositely charged anionic surfactants and cationic surfactants (CASs), which results in significant synergistic effects in interfacial properties due to electrostatic attraction to improve oil production at the given harsh conditions. The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high-salinity brine at 90°C. Comprehensive performance of the catanionic surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95°C. The coreflooding displacement experiments were performed using carbonate core plugs at 95°C to evaluate the potential of the optimal catanionic surfactant in improving oil recovery. Three catanionic surfactants with good compatibility were developed in this study. It appeared that the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was between 10−1 and 100 mN/m, a significant IFT reduction in the magnitude of 10−2 to 10−3 mN/m was observed by mixing the selected anionic surfactants and CASs. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the effectiveness of the catanionic surfactant. In microemulsion phase behavior studies, the developed catanionic surfactant solution in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorption quantities of the catanionic surfactants were lower than the values of the individual surfactants. All these indicated the feasibility of catanionic surfactants for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil recovery improvement beyond waterflooding. This work provides an efficient way to get surfactant formulations by mixing oppositely charged surfactants to obtain high performance in improving oil production under harsh conditions.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"101 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80436840","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Natural gas production in the Sichuan Basin reached 30×109 m3 in 2020, but the shortfall between this and the production goal of 50×109 m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs reduce the accuracy of formation water saturation calculations from Archie’s equation, which brings uncertainties to the reservoir characterization. Therefore, it is necessary to incorporate other methods as supplements to methods based on resistivities. In this paper, we outline a method that incorporates wireline-induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only used to estimate the mineralogy of the reservoir, but it also provides measurements, such as chlorine concentration and thermal neutron capture cross section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, hence formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivity measurements. Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud (OBM) environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOIs of different measurements must be considered when performing the fluid identification. Bound fluid saturation can reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must also be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs. In this paper, we discuss a novel combination of wireline logging tools for fluid identification in a tight carbonate reservoir in the Sichuan Basin. It reduces the uncertainty when estimating formation water saturation and when resistivity measurements are suppressed in OBM environments. The gas zones identified by the new method have promising predictions of gas production. This workflow can also be applied to other tight carbonate plays in China.
{"title":"Fluid Identification Derived from Formation Chlorine Measurements and Reservoir Characterization of Tight Carbonate in Sichuan Basin, China","authors":"Y. Wang, X. R. Zhao, K. Li","doi":"10.2118/205926-pa","DOIUrl":"https://doi.org/10.2118/205926-pa","url":null,"abstract":"\u0000 Natural gas production in the Sichuan Basin reached 30×109 m3 in 2020, but the shortfall between this and the production goal of 50×109 m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs reduce the accuracy of formation water saturation calculations from Archie’s equation, which brings uncertainties to the reservoir characterization. Therefore, it is necessary to incorporate other methods as supplements to methods based on resistivities.\u0000 In this paper, we outline a method that incorporates wireline-induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only used to estimate the mineralogy of the reservoir, but it also provides measurements, such as chlorine concentration and thermal neutron capture cross section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, hence formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivity measurements.\u0000 Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud (OBM) environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOIs of different measurements must be considered when performing the fluid identification. Bound fluid saturation can reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must also be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs.\u0000 In this paper, we discuss a novel combination of wireline logging tools for fluid identification in a tight carbonate reservoir in the Sichuan Basin. It reduces the uncertainty when estimating formation water saturation and when resistivity measurements are suppressed in OBM environments. The gas zones identified by the new method have promising predictions of gas production. This workflow can also be applied to other tight carbonate plays in China.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"113 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79822407","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Air-injection-based enhanced oil recovery (EOR) processes have historically been of great interest due to their high recovery potential and applicability to a wide range of reservoirs where other processes are not effective or economical. However, most operators require a certain level of confidence in the potential recovery from these (or any) process before committing resources; this is commonly achieved with the support of laboratory and reservoir simulation studies. Laboratory testing, including combustion tube, ramped temperature oxidation (RTO), and accelerating rate calorimeter (ARC) tests, can supply data for simple analytical models. It can also provide important insights into potential oxidation behaviors and oil recovery mechanisms. Similarly, reservoir simulation of some of those experiments can assist in the understanding of the process and may allow for the development of kinetic models that can be used for further reservoir modeling. However, due to sample size limitation and the unscaled nature of the experiments, these tests are not ideally suited to provide detailed or unique kinetic data for direct use in numerical simulators. In fact, the oxidation reactions are sufficiently complex that, regardless of how robust a thermal reservoir simulator may be, its predictive capability strongly depends on the engineer’s understanding of the process and ability to model the most relevant oxidation behaviors of the particular hydrocarbon reservoir under study. Over the past 50 years, the In-Situ Combustion Research Group (ISCRG) at the University of Calgary has dedicated its efforts toward the advancement of this technology. Under the leadership of Professor Gordon Moore, the ISCRG has performed a large number of combustion tests, designed and carried out many novel oxidation experiments, and also made important contributions to the numerical modeling of air-injection-based processes. Nevertheless, in spite of its long research history, the group acknowledges that there is still much that needs to be learned about the process. For example, two oils with the same physical properties such as viscosity and density can have significantly different oxidation behaviors, which are difficult to predict; this is one of the reasons the group continues to perform laboratory experiments and conduct research in this area. This paper describes some of the most important conceptual contributions made by the ISCRG based on their experimental results and how they have enhanced our understanding of the process. These continue to be an important source of knowledge toward the development of predictive reservoir simulation models, as it is very difficult, if not impossible, to properly model a physical problem one does not understand well. For instance, the fundamental equations used for mathematical modeling depend on selecting of the relevant physical mechanisms and assumptions made, and these are derived from experimental work. Similarly, when using
{"title":"New Insights into the Understanding of In-Situ Combustion: Important Considerations When Modeling the Process","authors":"D. Gutiérrez, D. Mallory","doi":"10.2118/212268-pa","DOIUrl":"https://doi.org/10.2118/212268-pa","url":null,"abstract":"\u0000 Air-injection-based enhanced oil recovery (EOR) processes have historically been of great interest due to their high recovery potential and applicability to a wide range of reservoirs where other processes are not effective or economical. However, most operators require a certain level of confidence in the potential recovery from these (or any) process before committing resources; this is commonly achieved with the support of laboratory and reservoir simulation studies.\u0000 Laboratory testing, including combustion tube, ramped temperature oxidation (RTO), and accelerating rate calorimeter (ARC) tests, can supply data for simple analytical models. It can also provide important insights into potential oxidation behaviors and oil recovery mechanisms. Similarly, reservoir simulation of some of those experiments can assist in the understanding of the process and may allow for the development of kinetic models that can be used for further reservoir modeling. However, due to sample size limitation and the unscaled nature of the experiments, these tests are not ideally suited to provide detailed or unique kinetic data for direct use in numerical simulators. In fact, the oxidation reactions are sufficiently complex that, regardless of how robust a thermal reservoir simulator may be, its predictive capability strongly depends on the engineer’s understanding of the process and ability to model the most relevant oxidation behaviors of the particular hydrocarbon reservoir under study.\u0000 Over the past 50 years, the In-Situ Combustion Research Group (ISCRG) at the University of Calgary has dedicated its efforts toward the advancement of this technology. Under the leadership of Professor Gordon Moore, the ISCRG has performed a large number of combustion tests, designed and carried out many novel oxidation experiments, and also made important contributions to the numerical modeling of air-injection-based processes. Nevertheless, in spite of its long research history, the group acknowledges that there is still much that needs to be learned about the process. For example, two oils with the same physical properties such as viscosity and density can have significantly different oxidation behaviors, which are difficult to predict; this is one of the reasons the group continues to perform laboratory experiments and conduct research in this area.\u0000 This paper describes some of the most important conceptual contributions made by the ISCRG based on their experimental results and how they have enhanced our understanding of the process. These continue to be an important source of knowledge toward the development of predictive reservoir simulation models, as it is very difficult, if not impossible, to properly model a physical problem one does not understand well. For instance, the fundamental equations used for mathematical modeling depend on selecting of the relevant physical mechanisms and assumptions made, and these are derived from experimental work. Similarly, when using ","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"8 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77177972","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. G. Askarova, E. Popov, K. Maerle, A. Cheremisin
A significant amount of oil is contained in carbonate reservoirs, but only half of that oil can be produced by secondary enhanced oil recovery (EOR) methods. However, substantial improvements were made in EOR techniques and the prediction of carbonate reservoir performance within the last decades. Nevertheless, existing flow-simulation computer programs failed to provide a reliable prediction of such reservoirs due to their high heterogeneity and the reactivity of the rock. Potentially, in-situ combustion (ISC) is considered effective in developing heavy oils in carbonate reservoirs. The combustion reactions between crude oil and heterogeneous rock matrices introduce additional complexity to the simulation process. Also, most of the laboratory experiments studying the reaction kinetics of the ISC process are performed on the crushed core. However, to minimize the risks, improve the control of the process, and overcome upscaling issues, physical simulation must be carried out under conditions as close to the reservoir as possible. Consolidated core material in combustion tube (CT) experiments is desirable for better simulating some reservoir conditions with synthetic packs and for the cases when actual preserved reservoir core material may be available. Studying the relative effects of porosity and packing properties (specific surface area, sand grain distribution, and cementation) on the fuel is essential to evaluating the process under actual field conditions. This work presents a set of medium-pressure CT (MPCT) tests on crushed and consolidated cores and analyzes the differences, limitations, and performances of both approaches. Two MPCT tests were performed to evaluate the ISC feasibility on the heavy-oil carbonate reservoir with an initial oil saturation level of 0.38 to 0.50. According to previously published experimental results, such oil saturation levels can help avoid oil banking. Both experiments were conducted at reservoir conditions to consider the phase behavior at elevated pressures and temperatures. The method used in this research allows approbation of the methodology of ISC tests using consolidated core at high pressure, ensuring pack and process integrity during the experiment. The influence of consolidated core caused by significantly lower porosity and more uniform porous media elements than those made with unconsolidated material on combustion performance was assessed. Valuable data for different variations of combustion experiments were generated. This work compared two tests and presented the combustion parameters for a stabilized combustion period, such as fuel and air requirements, recovery efficiency, front velocity, and composition of produced gases. The research intends to demonstrate the potential application problems and address issues that might arise during ISC application on target reservoirs, including the higher air flux required for lower porosity of consolidated core samples. The experimental results perf
{"title":"Comparative Study of In-Situ Combustion Tests on Consolidated and Crushed Cores","authors":"A. G. Askarova, E. Popov, K. Maerle, A. Cheremisin","doi":"10.2118/212270-pa","DOIUrl":"https://doi.org/10.2118/212270-pa","url":null,"abstract":"\u0000 A significant amount of oil is contained in carbonate reservoirs, but only half of that oil can be produced by secondary enhanced oil recovery (EOR) methods. However, substantial improvements were made in EOR techniques and the prediction of carbonate reservoir performance within the last decades. Nevertheless, existing flow-simulation computer programs failed to provide a reliable prediction of such reservoirs due to their high heterogeneity and the reactivity of the rock. Potentially, in-situ combustion (ISC) is considered effective in developing heavy oils in carbonate reservoirs. The combustion reactions between crude oil and heterogeneous rock matrices introduce additional complexity to the simulation process. Also, most of the laboratory experiments studying the reaction kinetics of the ISC process are performed on the crushed core. However, to minimize the risks, improve the control of the process, and overcome upscaling issues, physical simulation must be carried out under conditions as close to the reservoir as possible.\u0000 Consolidated core material in combustion tube (CT) experiments is desirable for better simulating some reservoir conditions with synthetic packs and for the cases when actual preserved reservoir core material may be available. Studying the relative effects of porosity and packing properties (specific surface area, sand grain distribution, and cementation) on the fuel is essential to evaluating the process under actual field conditions.\u0000 This work presents a set of medium-pressure CT (MPCT) tests on crushed and consolidated cores and analyzes the differences, limitations, and performances of both approaches. Two MPCT tests were performed to evaluate the ISC feasibility on the heavy-oil carbonate reservoir with an initial oil saturation level of 0.38 to 0.50. According to previously published experimental results, such oil saturation levels can help avoid oil banking. Both experiments were conducted at reservoir conditions to consider the phase behavior at elevated pressures and temperatures. The method used in this research allows approbation of the methodology of ISC tests using consolidated core at high pressure, ensuring pack and process integrity during the experiment. The influence of consolidated core caused by significantly lower porosity and more uniform porous media elements than those made with unconsolidated material on combustion performance was assessed. Valuable data for different variations of combustion experiments were generated. This work compared two tests and presented the combustion parameters for a stabilized combustion period, such as fuel and air requirements, recovery efficiency, front velocity, and composition of produced gases. The research intends to demonstrate the potential application problems and address issues that might arise during ISC application on target reservoirs, including the higher air flux required for lower porosity of consolidated core samples. The experimental results perf","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"38 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84841449","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T. Karamov, E. Leushina, E. Kozlova, M. Spasennykh
Organic matter-hosted pores are considered as the main type of porosity in organic-rich shales. At the same time, literature indicates the formation of pore space during pyrolysis of oil shales. However, controls, evolution, and types of organic porosity remain controversial. This study aims to experimentally investigate the evolution of organic pores in an organic-rich shale sample during thermal treatment. This paper reports the organic porosity evolution during an artificial maturation experiment of the Bazhenov Formation (BF) shale sample (West Siberian Petroleum Basin). The siliceous-argillaceous organic-rich shale immature nonporous rock sample was treated in an open system in the temperature range of 350–450°C with the step of 10°C. Organic porosity was characterized by the combination of broad ion beam (BIB) polishing and scanning electron microscopy (SEM). After each episode of treatment, the area of 1000×1000 μm was scanned with a resolution of 25 nm. The acquired mosaic SEM images were segmented by the neural network algorithm and quantitatively analyzed. We demonstrate direct experimental evidence that thermal maturation/thermal treatment influence on organic porosity development. Organic porosity evolution is shown within the individual organic matter (OM) particles throughout the experiment. Thermal treatment leads to the formation of two types of organic pores, which are shrinkage and spongy pores. The first shrinkage pores start to form after the evacuation of existing hydrocarbons; they are relatively large and might reach 7 µm. This type of pore dominates at the initial stages of treatment (350–390°C). Porosity at this stage does not exceed 1.4%. The second type is spongy pores, which are up to 3–5 μm in size and are potentially formed due to hydrocarbon generation from the kerogen. This type of porosity becomes major after 400°C. This is confirmed by the pore size distribution analysis. The porosity spikes up to 2.3% after 400°C and rises up to 2.9% after 450°C. Revealing of artificial organic porosity development during thermal treatment experiment shows the crucial importance of the thermal maturity level. The formation of pore space during the treatment is critical during the implementation of thermal enhanced oil recovery (EOR) technologies in shales for fluid flow, and a mandatory aspect that should be accounted during thermal EOR simulations.
{"title":"Broad Ion Beam–Scanning Electron Microscopy Characterization of Organic Porosity Evolution During Thermal Treatment of Bazhenov Shale Sample","authors":"T. Karamov, E. Leushina, E. Kozlova, M. Spasennykh","doi":"10.2118/210599-pa","DOIUrl":"https://doi.org/10.2118/210599-pa","url":null,"abstract":"\u0000 Organic matter-hosted pores are considered as the main type of porosity in organic-rich shales. At the same time, literature indicates the formation of pore space during pyrolysis of oil shales. However, controls, evolution, and types of organic porosity remain controversial. This study aims to experimentally investigate the evolution of organic pores in an organic-rich shale sample during thermal treatment.\u0000 This paper reports the organic porosity evolution during an artificial maturation experiment of the Bazhenov Formation (BF) shale sample (West Siberian Petroleum Basin). The siliceous-argillaceous organic-rich shale immature nonporous rock sample was treated in an open system in the temperature range of 350–450°C with the step of 10°C. Organic porosity was characterized by the combination of broad ion beam (BIB) polishing and scanning electron microscopy (SEM). After each episode of treatment, the area of 1000×1000 μm was scanned with a resolution of 25 nm. The acquired mosaic SEM images were segmented by the neural network algorithm and quantitatively analyzed.\u0000 We demonstrate direct experimental evidence that thermal maturation/thermal treatment influence on organic porosity development. Organic porosity evolution is shown within the individual organic matter (OM) particles throughout the experiment. Thermal treatment leads to the formation of two types of organic pores, which are shrinkage and spongy pores. The first shrinkage pores start to form after the evacuation of existing hydrocarbons; they are relatively large and might reach 7 µm. This type of pore dominates at the initial stages of treatment (350–390°C). Porosity at this stage does not exceed 1.4%. The second type is spongy pores, which are up to 3–5 μm in size and are potentially formed due to hydrocarbon generation from the kerogen. This type of porosity becomes major after 400°C. This is confirmed by the pore size distribution analysis. The porosity spikes up to 2.3% after 400°C and rises up to 2.9% after 450°C.\u0000 Revealing of artificial organic porosity development during thermal treatment experiment shows the crucial importance of the thermal maturity level. The formation of pore space during the treatment is critical during the implementation of thermal enhanced oil recovery (EOR) technologies in shales for fluid flow, and a mandatory aspect that should be accounted during thermal EOR simulations.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"117 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73855484","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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