Pub Date : 2026-02-01Epub Date: 2025-12-01DOI: 10.1016/j.petsci.2025.11.045
Jun Zhang , Jin-Yuan Zhang , Jia Zeng , Zhe-Jun Pan , Yu-Wei Li , Zi-Yuan Cong
For shale reservoir operations, assessing the brittleness of anisotropic shales is vital of optimizing wellbore stability analysis and fracturing design. Current brittleness indices lack effectiveness in characterizing shale brittleness anisotropy. Consequently, the experimental results reported in this paper derived from triaxial tests conducted on shale core samples from the Qingshankou Formation of the Songliao Basin. This study investigates the anisotropy of shale failure patterns and mechanical properties with respect to the bedding plane dip angle (θ), and quantifies the effect of confining pressure. Building on the cohesion weakening and friction strengthening (CWFS) theory, we established a novel triaxial brittleness index (Bt). This index uniquely combines the uniaxial brittleness index (Bu), reflecting inherent brittleness, with the brittleness weakening coefficient (Bw), quantifying the effect of confining pressure. Assessment of the anisotropic brittleness of shale based on Bt under varying confining pressures reveals that Bt first increases but then decreases with increasing θ. The brittleness peaks at θ = 0° and reaches its lowest point at θ = 60°, a trend that aligns closely with the observed variations in the failure patterns of shale. Furthermore, the ability of the confining pressure to decrease shale brittleness varies with θ. At θ = 0°, the uniaxial brittleness is the highest, but the confining pressure has the strongest weakening effect on shale brittleness. In contrast, the uniaxial brittleness at θ = 90° is second only to that at 0°, but the brittleness in this direction is least affected by the confining pressure. Compared with the five existing brittleness indices, the proposed index accounts for both inherent and apparent brittleness. It is more sensitive to internal lithological characteristics and external stress conditions and has strong potential for integration with geophysical data. This study provides valuable guidance for sweet spot identification, wellbore stability assessment, and fracturing scheme optimization in shale oil and gas exploration.
{"title":"Application of a CWFS model-based brittleness index for evaluating anisotropic brittleness in terrestrial shale under triaxial stress","authors":"Jun Zhang , Jin-Yuan Zhang , Jia Zeng , Zhe-Jun Pan , Yu-Wei Li , Zi-Yuan Cong","doi":"10.1016/j.petsci.2025.11.045","DOIUrl":"10.1016/j.petsci.2025.11.045","url":null,"abstract":"<div><div>For shale reservoir operations, assessing the brittleness of anisotropic shales is vital of optimizing wellbore stability analysis and fracturing design. Current brittleness indices lack effectiveness in characterizing shale brittleness anisotropy. Consequently, the experimental results reported in this paper derived from triaxial tests conducted on shale core samples from the Qingshankou Formation of the Songliao Basin. This study investigates the anisotropy of shale failure patterns and mechanical properties with respect to the bedding plane dip angle (<em>θ</em>), and quantifies the effect of confining pressure. Building on the cohesion weakening and friction strengthening (CWFS) theory, we established a novel triaxial brittleness index (<em>B</em><sub>t</sub>). This index uniquely combines the uniaxial brittleness index (<em>B</em><sub>u</sub>), reflecting inherent brittleness, with the brittleness weakening coefficient (<em>B</em><sub>w</sub>), quantifying the effect of confining pressure. Assessment of the anisotropic brittleness of shale based on <em>B</em><sub>t</sub> under varying confining pressures reveals that <em>B</em><sub>t</sub> first increases but then decreases with increasing <em>θ</em>. The brittleness peaks at <em>θ</em> = 0° and reaches its lowest point at <em>θ</em> = 60°, a trend that aligns closely with the observed variations in the failure patterns of shale. Furthermore, the ability of the confining pressure to decrease shale brittleness varies with <em>θ</em>. At <em>θ</em> = 0°, the uniaxial brittleness is the highest, but the confining pressure has the strongest weakening effect on shale brittleness. In contrast, the uniaxial brittleness at <em>θ</em> = 90° is second only to that at 0°, but the brittleness in this direction is least affected by the confining pressure. Compared with the five existing brittleness indices, the proposed index accounts for both inherent and apparent brittleness. It is more sensitive to internal lithological characteristics and external stress conditions and has strong potential for integration with geophysical data. This study provides valuable guidance for sweet spot identification, wellbore stability assessment, and fracturing scheme optimization in shale oil and gas exploration.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 742-761"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418374","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-11-08DOI: 10.1016/j.petsci.2025.11.010
Hong-Xian Kuang , Zhou-Hua Wang , Na Jia , Han-Min Tu , Yun Li , Huang Liu , Ping Guo , Zi-Yan Wang
Shale reservoirs are dominated by nanopores, where wall-fluid adsorption and anomalous fluid intermolecular interactions lead to substantial deviations from conventional equation of state (EOS) predictions. This study proposes a modified Peng-Robinson equation of state (m-PR EOS) that incorporates two innovative key corrections: (1) a refined molar volume term accounting for wall-fluid adsorption effects; and (2) introduction of the contact angle in the attractive term to rectify anomalous fluid intermolecular interactions. The m-PR EOS quantitatively captures the shifts in critical properties of confined hydrocarbons and pioneeringly integrates critical pore size determination, identifying confinement thresholds for pure hydrocarbons. The critical pore radii of methane were determined as 18.62 nm (based on temperature shift) and 51.33 nm (based on pressure shift). The analysis reveals that hydrocarbons with larger Lennard-Jones molecular sizes exhibit larger critical pore sizes and greater deviations in critical properties at the same confinement scale. The model validated with binary hydrocarbons was applied to simulate pore-size-dependent phase behavior in shale condensate systems and Constant Composition Expansion experiments. Results demonstrate that reducing pore size causes phase envelope to contract towards the lower-left quadrant in the P-T phase diagram, with accelerated contraction rates. Constant Composition Expansion simulations show that the retrograde condensation volume curve exhibits a similar contraction trend as the phase envelope. By incorporating wettability effects, the m-PR EOS model extends its applicability to a wide range of reservoirs. The m-PR EOS provides a thermodynamic foundation for accurately predicting nanoscale phase behavior and optimizing condensate recovery in unconventional reservoirs.
{"title":"Modified Peng-Robinson equation of state for confined fluids: Critical pore size and phase behavior in shale nanopores","authors":"Hong-Xian Kuang , Zhou-Hua Wang , Na Jia , Han-Min Tu , Yun Li , Huang Liu , Ping Guo , Zi-Yan Wang","doi":"10.1016/j.petsci.2025.11.010","DOIUrl":"10.1016/j.petsci.2025.11.010","url":null,"abstract":"<div><div>Shale reservoirs are dominated by nanopores, where wall-fluid adsorption and anomalous fluid intermolecular interactions lead to substantial deviations from conventional equation of state (EOS) predictions. This study proposes a modified Peng-Robinson equation of state (m-PR EOS) that incorporates two innovative key corrections: (1) a refined molar volume term accounting for wall-fluid adsorption effects; and (2) introduction of the contact angle in the attractive term to rectify anomalous fluid intermolecular interactions. The m-PR EOS quantitatively captures the shifts in critical properties of confined hydrocarbons and pioneeringly integrates critical pore size determination, identifying confinement thresholds for pure hydrocarbons. The critical pore radii of methane were determined as 18.62 nm (based on temperature shift) and 51.33 nm (based on pressure shift). The analysis reveals that hydrocarbons with larger Lennard-Jones molecular sizes exhibit larger critical pore sizes and greater deviations in critical properties at the same confinement scale. The model validated with binary hydrocarbons was applied to simulate pore-size-dependent phase behavior in shale condensate systems and Constant Composition Expansion experiments. Results demonstrate that reducing pore size causes phase envelope to contract towards the lower-left quadrant in the <em>P-T</em> phase diagram, with accelerated contraction rates. Constant Composition Expansion simulations show that the retrograde condensation volume curve exhibits a similar contraction trend as the phase envelope. By incorporating wettability effects, the m-PR EOS model extends its applicability to a wide range of reservoirs. The m-PR EOS provides a thermodynamic foundation for accurately predicting nanoscale phase behavior and optimizing condensate recovery in unconventional reservoirs.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 804-817"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417838","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shale is a strongly heterogeneous anisotropic porous medium with a complex nanopore structure. Therefore, accurately describing the distribution and occurrence of shale gas in the intricate pore structure of shale is difficult. The simplified local density (SLD) theory constitutes an effective and widely accepted approach for characterizing the adsorption mechanism within the intricate pore structures of nanoporous shale. On the basis of SLD theory, this paper proposes for the first time a new adsorption model that considers spherical pores to accurately describe the adsorption behavior within the complex pore structure of shale containing spherical pores. Compared with conventional adsorption theory models and traditional SLD models, not only were the accuracy and applicability of the new model verified, but it was also found that the new model could significantly improve the effective calculation accuracy even with fewer fitting parameters. Furthermore, an analysis of and discussing the adsorption behavior of methane in shale pores with different pore structures (including pore geometries, specific surface areas, diameters and volumes) revealed that the pore structure significantly affects the adsorption behavior of methane. The effects of the number of pore wall solid molecular layers that characterize different fluid-solid interactions and the adjustable parameters for repulsive forces that characterize different fluid-fluid interactions on the methane adsorption isotherms and density distributions were also explored. The results indicate that the newly developed spherical SLD model may provide new insights into the occurrence mode of shale gas in complex shale pores and offer valuable references for reserve assessment and extraction efficiency optimization in shale gas exploration.
{"title":"Adsorption behavior of spherical pores in shale integrated with simplified local density theory","authors":"Yu Zhao, Da-Guo Quan, Chao-Lin Wang, Kun-Peng Zhang","doi":"10.1016/j.petsci.2025.09.012","DOIUrl":"10.1016/j.petsci.2025.09.012","url":null,"abstract":"<div><div>Shale is a strongly heterogeneous anisotropic porous medium with a complex nanopore structure. Therefore, accurately describing the distribution and occurrence of shale gas in the intricate pore structure of shale is difficult. The simplified local density (SLD) theory constitutes an effective and widely accepted approach for characterizing the adsorption mechanism within the intricate pore structures of nanoporous shale. On the basis of SLD theory, this paper proposes for the first time a new adsorption model that considers spherical pores to accurately describe the adsorption behavior within the complex pore structure of shale containing spherical pores. Compared with conventional adsorption theory models and traditional SLD models, not only were the accuracy and applicability of the new model verified, but it was also found that the new model could significantly improve the effective calculation accuracy even with fewer fitting parameters. Furthermore, an analysis of and discussing the adsorption behavior of methane in shale pores with different pore structures (including pore geometries, specific surface areas, diameters and volumes) revealed that the pore structure significantly affects the adsorption behavior of methane. The effects of the number of pore wall solid molecular layers that characterize different fluid-solid interactions and the adjustable parameters for repulsive forces that characterize different fluid-fluid interactions on the methane adsorption isotherms and density distributions were also explored. The results indicate that the newly developed spherical SLD model may provide new insights into the occurrence mode of shale gas in complex shale pores and offer valuable references for reserve assessment and extraction efficiency optimization in shale gas exploration.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 692-711"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418364","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-10-18DOI: 10.1016/j.petsci.2025.10.011
Mohammadfarid Ghasemi , Abdorrazagh Javid
Permeability estimation is pivotal in reservoir characterization; however, prevailing methods lack a standardized approach. Traditionally reliant on core samples, permeability assessment encounters limitations across diverse thicknesses and wells. An innovative core-independent two-step rock physics template (RPT) can be designed to estimate elastic and conductive properties. The suggested RPT employs the T-matrix method to leverage well-log data encompassing porosity, fluid saturation, and various textural parameters. The estimation process for textural parameters involves addressing uncertainties through the fixed form variational inference (FFVB) with the trust region reflective optimization algorithm. These uncertainties span estimated textural parameters, seismic wave propagation velocity, electrical resistivity, and hydraulic permeability. Micro and macro voids, micro-spherical pores porosity, and their semi-axis are modeled using Beta distributions for both prior and variational families. The noise in the model assumes an inverse gamma distribution for sonic travel time and true formation resistivity. Validation of the proposed method is achieved by comparing the FFVB results with Metropolis Hasting's sampling method in three depths and also through geological observations and experimental analyses on available core samples. The inverse problem, involving the determination of textural parameters through sonic travel time and resistivity, is solved. Subsequently, the forward problem is addressed to estimate permeability. The robustness of the inverse problem is underscored by minimal discrepancies between measured sonic travel times, true formation resistivity values, and the results of the forward problem. The method demonstrates its effectiveness in permeability estimation, even in regions lacking core data, thereby emphasizing its reliability and applicability in diverse geological settings.
{"title":"Permeability estimation using rock physics modeling and variational Bayes inversion","authors":"Mohammadfarid Ghasemi , Abdorrazagh Javid","doi":"10.1016/j.petsci.2025.10.011","DOIUrl":"10.1016/j.petsci.2025.10.011","url":null,"abstract":"<div><div>Permeability estimation is pivotal in reservoir characterization; however, prevailing methods lack a standardized approach. Traditionally reliant on core samples, permeability assessment encounters limitations across diverse thicknesses and wells. An innovative core-independent two-step rock physics template (RPT) can be designed to estimate elastic and conductive properties. The suggested RPT employs the T-matrix method to leverage well-log data encompassing porosity, fluid saturation, and various textural parameters. The estimation process for textural parameters involves addressing uncertainties through the fixed form variational inference (FFVB) with the trust region reflective optimization algorithm. These uncertainties span estimated textural parameters, seismic wave propagation velocity, electrical resistivity, and hydraulic permeability. Micro and macro voids, micro-spherical pores porosity, and their semi-axis are modeled using Beta distributions for both prior and variational families. The noise in the model assumes an inverse gamma distribution for sonic travel time and true formation resistivity. Validation of the proposed method is achieved by comparing the FFVB results with Metropolis Hasting's sampling method in three depths and also through geological observations and experimental analyses on available core samples. The inverse problem, involving the determination of textural parameters through sonic travel time and resistivity, is solved. Subsequently, the forward problem is addressed to estimate permeability. The robustness of the inverse problem is underscored by minimal discrepancies between measured sonic travel times, true formation resistivity values, and the results of the forward problem. The method demonstrates its effectiveness in permeability estimation, even in regions lacking core data, thereby emphasizing its reliability and applicability in diverse geological settings.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 656-679"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418366","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-10-10DOI: 10.1016/j.petsci.2025.09.042
Hang Yang , Jia-Qiang Jing , Jie Sun , Jia-Tong Tan
The impact of wax on the formation of hydrates has not yet been established due to the inherent complexity of oil–water (O/W) mixtures. The O/W system has not been as extensively studied. In light of the considerations above, the present study involved the preparation of O/W emulsions through the addition of Tween-80. The investigation encompasses the impact of wax on hydrate formation in the presence or absence of Tween-80 under the influence of varying wax contents. The coupling of Tween-80 and waxes facilitated nucleation because of the heterogeneous nucleation effect of the hydrates. The induction period of hydrates first increased and then decreased with increasing wax content. At low wax content, the emulsion was in an W/O/W state, and the wax crystals precipitated in the oil encapsulated some of the water droplets, leading to a reduction of water in the outer phase of the emulsion, which was unfavorable for hydrate nucleation. Differences in the contribution of waxes to hydrate formation in non-emulsified, water-dominated and oil-dominated systems were clarified in conjunction with our previous studies. This study contributes to a comprehensive understanding of the effect of wax on hydrate formation.
{"title":"Study of the effect of wax on carbon dioxide hydrate formation in oil–water mixture with high water content","authors":"Hang Yang , Jia-Qiang Jing , Jie Sun , Jia-Tong Tan","doi":"10.1016/j.petsci.2025.09.042","DOIUrl":"10.1016/j.petsci.2025.09.042","url":null,"abstract":"<div><div>The impact of wax on the formation of hydrates has not yet been established due to the inherent complexity of oil–water (O/W) mixtures. The O/W system has not been as extensively studied. In light of the considerations above, the present study involved the preparation of O/W emulsions through the addition of Tween-80. The investigation encompasses the impact of wax on hydrate formation in the presence or absence of Tween-80 under the influence of varying wax contents. The coupling of Tween-80 and waxes facilitated nucleation because of the heterogeneous nucleation effect of the hydrates. The induction period of hydrates first increased and then decreased with increasing wax content. At low wax content, the emulsion was in an W/O/W state, and the wax crystals precipitated in the oil encapsulated some of the water droplets, leading to a reduction of water in the outer phase of the emulsion, which was unfavorable for hydrate nucleation. Differences in the contribution of waxes to hydrate formation in non-emulsified, water-dominated and oil-dominated systems were clarified in conjunction with our previous studies. This study contributes to a comprehensive understanding of the effect of wax on hydrate formation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 939-953"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417684","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-09-20DOI: 10.1016/j.petsci.2025.09.029
Ming-Ming Jiang , Xiao-Fei Fu , Quan-You Liu
Deformation band research has long been hindered by limited understanding of structural characteristics and physical properties during actual deformation processes. To address these knowledge gaps, this study systematically reviews experimental simulation methodologies through integrated approaches. Combining field observations with our newly developed ring shear tests for consolidated rocks, we investigate: formation mechanisms of deformation bands; key controlling factors including effective normal stress, shear displacement, clay content, mineral composition, porosity, particle size distribution, sorting, and cementation; comparative evaluation of experimental techniques (ring shear vs. direct shear vs. triaxial shear vs. sandbox modeling). Our analysis reveals two critical experimental parameters: effective normal stress and shear displacement. Notably, the advancement of consolidated rock-specific ring shear apparatus enables centimeter-scale displacement simulations, significantly enhancing deformation band experimentation. Current challenges in field measurement, image analysis, and 3D modeling are discussed with proposed solutions. Future directions emphasize: in-situ permeability testing, quantitative analysis frameworks, cementation dynamics, and numerical simulation optimization. This work aims to highlight deformation bands' crucial role in fluid migration and reservoir preservation while providing methodological guidance for designing simulation experiments. The compiled experimental protocols and analytical techniques offer researchers a systematic reference for deformation band investigations.
{"title":"The development of deformation bands from experiments: Review and perspective","authors":"Ming-Ming Jiang , Xiao-Fei Fu , Quan-You Liu","doi":"10.1016/j.petsci.2025.09.029","DOIUrl":"10.1016/j.petsci.2025.09.029","url":null,"abstract":"<div><div>Deformation band research has long been hindered by limited understanding of structural characteristics and physical properties during actual deformation processes. To address these knowledge gaps, this study systematically reviews experimental simulation methodologies through integrated approaches. Combining field observations with our newly developed ring shear tests for consolidated rocks, we investigate: formation mechanisms of deformation bands; key controlling factors including effective normal stress, shear displacement, clay content, mineral composition, porosity, particle size distribution, sorting, and cementation; comparative evaluation of experimental techniques (ring shear vs. direct shear vs. triaxial shear vs. sandbox modeling). Our analysis reveals two critical experimental parameters: effective normal stress and shear displacement. Notably, the advancement of consolidated rock-specific ring shear apparatus enables centimeter-scale displacement simulations, significantly enhancing deformation band experimentation. Current challenges in field measurement, image analysis, and 3D modeling are discussed with proposed solutions. Future directions emphasize: in-situ permeability testing, quantitative analysis frameworks, cementation dynamics, and numerical simulation optimization. This work aims to highlight deformation bands' crucial role in fluid migration and reservoir preservation while providing methodological guidance for designing simulation experiments. The compiled experimental protocols and analytical techniques offer researchers a systematic reference for deformation band investigations.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 563-581"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418365","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-11-10DOI: 10.1016/j.petsci.2025.11.012
Hai-Hua Pei , Jian-Wei Zhao , Yang Liu , Jian Zhang , Gui-Cai Zhang
To address the critical stability and mobility control limitations of conventional surfactant-stabilized emulsions, this study introduces a novel Pickering emulsion system stabilized by lauramidopropylamine oxide (LAO)-modified SiO2 nanoparticles for enhanced heavy oil recovery. An aromatic hydrocarbon mixture was used as the oil phase, and the emulsion formulation (0.05 wt% LAO, pH 7.0) was systematically optimized through stability evaluations and rheological analyses. The optimized emulsion exhibited high stability, reversible shear-thinning behavior (> 90% viscosity recovery post-shearing), and predominantly elastic viscoelastic characteristics (G′/G″ > 10), which are attributed to the rigid interfacial film formed by LAO-modified SiO2 nanoparticles. Core flooding tests demonstrated exceptional plugging performance (resistance coefficient, FR = 124.3; residual resistance coefficient, FRR = 24.1) and achieved 29.6% incremental oil recovery—significantly exceeding conventional surfactant-stabilized emulsions (11.1%). A heterogeneous dual-core flooding experiment (permeability contrast = 5:1) confirmed superior conformance control with 33.6% tertiary oil recovery. Microscopic visualization revealed three synergistic mechanisms: (1) viscosity reduction and emulsification for enhanced heavy oil mobility; (2) flow diversion via Jamin effect-induced pore-throat blockage; and (3) pore-scale viscoelastic mobilization of residual oil. These mechanisms collectively enhanced macroscopic sweep efficiency and microscopic displacement efficiency, substantially improving heavy oil recovery in heterogeneous reservoirs. This work provides fundamental insights into Pickering emulsion transport in porous media and establishes a practical strategy for enhanced heavy oil recovery in heterogeneous reservoirs.
{"title":"Mechanistic insights into amine-oxide-modified silica nanoparticle-stabilized Pickering emulsions for enhanced heavy oil recovery in heterogeneous reservoirs","authors":"Hai-Hua Pei , Jian-Wei Zhao , Yang Liu , Jian Zhang , Gui-Cai Zhang","doi":"10.1016/j.petsci.2025.11.012","DOIUrl":"10.1016/j.petsci.2025.11.012","url":null,"abstract":"<div><div>To address the critical stability and mobility control limitations of conventional surfactant-stabilized emulsions, this study introduces a novel Pickering emulsion system stabilized by lauramidopropylamine oxide (LAO)-modified SiO<sub>2</sub> nanoparticles for enhanced heavy oil recovery. An aromatic hydrocarbon mixture was used as the oil phase, and the emulsion formulation (0.05 wt% LAO, pH 7.0) was systematically optimized through stability evaluations and rheological analyses. The optimized emulsion exhibited high stability, reversible shear-thinning behavior (> 90% viscosity recovery post-shearing), and predominantly elastic viscoelastic characteristics (<em>G′</em>/<em>G″</em> > 10), which are attributed to the rigid interfacial film formed by LAO-modified SiO<sub>2</sub> nanoparticles. Core flooding tests demonstrated exceptional plugging performance (resistance coefficient, <em>F</em><sub>R</sub> = 124.3; residual resistance coefficient, <em>F</em><sub>RR</sub> = 24.1) and achieved 29.6% incremental oil recovery—significantly exceeding conventional surfactant-stabilized emulsions (11.1%). A heterogeneous dual-core flooding experiment (permeability contrast = 5:1) confirmed superior conformance control with 33.6% tertiary oil recovery. Microscopic visualization revealed three synergistic mechanisms: (1) viscosity reduction and emulsification for enhanced heavy oil mobility; (2) flow diversion via Jamin effect-induced pore-throat blockage; and (3) pore-scale viscoelastic mobilization of residual oil. These mechanisms collectively enhanced macroscopic sweep efficiency and microscopic displacement efficiency, substantially improving heavy oil recovery in heterogeneous reservoirs. This work provides fundamental insights into Pickering emulsion transport in porous media and establishes a practical strategy for enhanced heavy oil recovery in heterogeneous reservoirs.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 882-896"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417846","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-11-22DOI: 10.1016/j.petsci.2025.11.035
Chao-Fan Zhu , Tan-En Jiang , Shan-Shan Yao , Jia-Zong Li , Rui Jia , Wei Guo
The autothermic pyrolysis in-situ conversion process for oil shale (ATS) offers the advantages of low development costs and the capability to exploit deep oil shale resources. However, oil shale formations with low oil content encounter the challenge of insufficient heat-generating donors in the thermal cracking residue, making it difficult to sustain the autogenous thermal reaction through oxidative exotherm. In this study, we propose a natural gas-assisted autogenous thermal in-situ conversion technology (H-ATS) designed to develop low oil content shale, and we analyze its mechanism through numerical simulation across oil shales with varying oil contents. The results show that introducing 2.0% natural gas into the injected air successfully triggers the autogenous thermal reaction in low-oil-content shale, achieving an energy efficiency of 3.70. For medium oil content shale, a 2.0% natural gas addition, and for high oil content shale, a 4.0% addition, significantly reduces the gas compression energy required, enhancing energy efficiency to 8.11 and 13.04, respectively—representing improvements of 29.47% and 19.19% over the ATS process alone. This study evaluates the applicability of H-ATS technology across various oil shale formations, providing a new approach for the commercialization of in-situ conversion technology.
{"title":"Numerical investigation of natural gas-enhanced autothermic pyrolysis for optimizing in-situ conversion in oil shale","authors":"Chao-Fan Zhu , Tan-En Jiang , Shan-Shan Yao , Jia-Zong Li , Rui Jia , Wei Guo","doi":"10.1016/j.petsci.2025.11.035","DOIUrl":"10.1016/j.petsci.2025.11.035","url":null,"abstract":"<div><div>The autothermic pyrolysis in-situ conversion process for oil shale (ATS) offers the advantages of low development costs and the capability to exploit deep oil shale resources. However, oil shale formations with low oil content encounter the challenge of insufficient heat-generating donors in the thermal cracking residue, making it difficult to sustain the autogenous thermal reaction through oxidative exotherm. In this study, we propose a natural gas-assisted autogenous thermal in-situ conversion technology (H-ATS) designed to develop low oil content shale, and we analyze its mechanism through numerical simulation across oil shales with varying oil contents. The results show that introducing 2.0% natural gas into the injected air successfully triggers the autogenous thermal reaction in low-oil-content shale, achieving an energy efficiency of 3.70. For medium oil content shale, a 2.0% natural gas addition, and for high oil content shale, a 4.0% addition, significantly reduces the gas compression energy required, enhancing energy efficiency to 8.11 and 13.04, respectively—representing improvements of 29.47% and 19.19% over the ATS process alone. This study evaluates the applicability of H-ATS technology across various oil shale formations, providing a new approach for the commercialization of in-situ conversion technology.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 762-776"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417832","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2026-02-01Epub Date: 2025-11-20DOI: 10.1016/j.petsci.2025.11.032
Yi-Di Wang , Xu Zhang , Xin-Yi Feng , Bin Liu , Yuan Pan , Guang-Zheng Sun , Hong-Yang Lv , Feng-Yu Tian , Bin Dong , Yi-Chuan Li , Chen-Guang Liu , Yong-Ming Chai
With the increasing heavy and inferior quality of global oil resources, the efficient utilization of crude oil has become a critical challenge to be solved in the energy field. This work intends to propose a feasible way of crude oil pretreatment in the refining process. A comparison of the comprehensive performance differences between thermal processing (TP) and slurry phase hydroupgrading (SPH) treatments revealed that SPH had a great upgrading effect for Arabian heavy crude oil under 390 °C and oil-soluble MoS2 catalyst. Compared with the feedstock, the asphaltene content of TP product increased by 13.2 wt%, that in SPH product dropped by about 19.8 wt%. And the total distillate yield (≤540 °C) of SPH increased by 4.4 wt% compared to the TP. The results of SARA separation and X-Ray Diffraction (XRD) showed that SPH can not only inhibit the occurrence of free radical reactions, but also dissociate the original asphaltene. The detailed composition of the processed samples was characterized by gas chromatography-mass spectrometry (GC-MS) and electrospray ionization orbitrap mass spectrometry (ESI Orbitrap MS) to explore the molecular transformation mechanism of different processes. There are a considerable number of –S– bonds in asphaltene as important structural connection hubs. The process of SPH can promote the production of light hydrocarbons while effectively removing heteroatom compounds. Finally, we considered that it is necessary to carry out the SPH pretreatment for Arabian heavy crude oil.
随着全球石油资源的重质劣质化日益严重，原油的高效利用已成为能源领域亟待解决的难题。本工作旨在提出一种可行的原油预处理方法。对比了热处理（TP）和浆相加氢处理（SPH）的综合性能差异，发现在390°C条件下，在油溶性MoS2催化剂条件下，SPH对阿拉伯重质原油有较好的提质效果。与原料相比，TP产品沥青质含量提高了13.2%，SPH产品沥青质含量下降了约19.8%。与TP相比，SPH的总馏出物收率（≤540°C）提高了4.4 wt%。SARA分离和x射线衍射（XRD）结果表明，SPH不仅能抑制自由基反应的发生，还能解离原始沥青质。采用气相色谱-质谱（GC-MS）和电喷雾电离轨道阱质谱（ESI orbitrap MS）对加工样品的详细组成进行表征，探讨不同工艺的分子转化机理。沥青质中存在大量的- s -键，是重要的结构连接枢纽。SPH工艺可以促进轻烃的生成，同时有效地去除杂原子化合物。最后，我们认为有必要对阿拉伯重质原油进行SPH预处理。
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Pub Date : 2026-02-01Epub Date: 2025-11-01DOI: 10.1016/j.petsci.2025.10.028
Yuan-Wei Sun , Jin-Sheng Sun , Kai-He Lv , Jing-Ping Liu , Chen-Jing Shi , Tai-Feng Zhang , Yu-Fan Zheng , Han Yan , Ye-Cheng Li
<div><div>Acrylamide-based polymers have been widely applied in drilling fluids due to their excellent water solubility, structural tunability, and adaptability to various fluid systems. However, under high-temperature downhole conditions, these polymers are prone to molecular chain degradation, conformational collapse, and reduced adsorption capacity, resulting in a significant decline in rheological control and filtration loss performance. These limitations severely restrict their application in high-temperature wells. Enhancing the structural stability and functional durability of polymers under elevated temperatures has become a critical challenge in the development of high-performance drilling fluid materials. Isoprenol polyoxyethylene ether (TPEG) has been demonstrated to improve the thermal resistance of acrylamide-based polymers. Nevertheless, incorporating TPEG into polymer chains contradicts the conventional design paradigm that seeks to eliminate thermally labile structures in high-temperature-resistant polymers. Therefore, elucidating the microscopic mechanisms by which TPEG modulates polymer chain evolution, conformational behavior, thermal degradation pathways, and adsorption characteristics at elevated temperatures is essential to understanding its synergistic effect. In this study, isoprenol polyoxyethylene ether (the most commonly used type with a molecular weight of 2400 was chosen, TPEG-2400) was introduced into a DMAA/AMPS acrylamide-based copolymer system and systematically compared with conventional DMAA/AMPS binary copolymers. The incorporation of TPEG-2400 significantly enhanced the thermal conformational stability and clay adsorption capacity of the polymer, enabling the drilling fluid to retain favorable rheological and filtration properties even after aging at 220 °C. The mechanism of action was elucidated by correlating changes in the physicochemical properties of the polymer with the analysis of its thermal degradation products. The highly flexible polyether structure was found to hinder interchain entanglement and coiling, while the strongly hydrophilic polyether segments formed a robust hydration layer, increasing electrostatic repulsion between clay particles. Moreover, the polyether chains may exhibit a “self-sacrificing” behavior under high-temperature conditions, preferentially decomposing to protect key functional groups such as amide moieties from thermal damage. This cooperative effect, from both conformational and thermodynamic perspectives, contributes to delaying polymer failure. It is concluded that the functional behavior of the segment structure plays a more significant role than its intrinsic thermal stability in enhancing the effective operating temperature of acrylamide-based polymers in drilling fluids. This counterintuitive yet strategically effective approach—introducing structurally specific but thermally less stable segments to achieve performance enhancement—offers a novel design perspective fo
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