Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.07.009
H.A. El Nagy , Elsayed H. Eltamany , Mostafa A.A. Mahmoud , Ahmed Z. Ibrahim , Sherin A.M. Ali
Resins are a significant component of crude oil, distinct from asphaltenes, and play a crucial role in influencing both rheological properties and flow characteristics. Understanding resin behavior is particularly important in crude oil operations and offshore operations, where flow assurance challenges can arise. This review article focuses on the impact of resins on the flow and rheological properties of crude oil. It examines the various compositions of resins and the molecular interactions between resins and asphaltenes that determine the viscosity and stability of crude oil. The presence of high concentrations of resins in certain crude oils can complicate flow assurance and pipeline transportation. Recent advancements in chemical treatments and additive technologies have addressed these challenges. This review highlights emerging research areas and technologies aimed at improving the understanding of resin behavior under extreme conditions, such as high-pressure and high-temperature reservoirs. Through this comprehensive analysis, the review aims to provide valuable insights into the role of resins in crude oil flow, guiding future research and innovations in petroleum engineering.
{"title":"The role of resins in crude oil rheology and flow assurance: A comprehensive review","authors":"H.A. El Nagy , Elsayed H. Eltamany , Mostafa A.A. Mahmoud , Ahmed Z. Ibrahim , Sherin A.M. Ali","doi":"10.1016/j.petlm.2025.07.009","DOIUrl":"10.1016/j.petlm.2025.07.009","url":null,"abstract":"<div><div>Resins are a significant component of crude oil, distinct from asphaltenes, and play a crucial role in influencing both rheological properties and flow characteristics. Understanding resin behavior is particularly important in crude oil operations and offshore operations, where flow assurance challenges can arise. This review article focuses on the impact of resins on the flow and rheological properties of crude oil. It examines the various compositions of resins and the molecular interactions between resins and asphaltenes that determine the viscosity and stability of crude oil. The presence of high concentrations of resins in certain crude oils can complicate flow assurance and pipeline transportation. Recent advancements in chemical treatments and additive technologies have addressed these challenges. This review highlights emerging research areas and technologies aimed at improving the understanding of resin behavior under extreme conditions, such as high-pressure and high-temperature reservoirs. Through this comprehensive analysis, the review aims to provide valuable insights into the role of resins in crude oil flow, guiding future research and innovations in petroleum engineering.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 391-409"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989966","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.05.005
Wenzheng Li , Hua Jiang , Xiaodong Fu , Yuan He , Mingfeng Gu , Nan Su , Shiyu Ma , Shugen Liu , Yongxiao Wang , Xuefei Yang
Based on the drilling, logging and field analysis, this paper discusses the lithofacies paleogeography of the Ordovician and its petroleum potential in the Middle-Upper Yangtze Area, South China. Results show that Ordovician of the Middle-Upper Yangtze Region can be divided into Tongzi Formation, Honghuayuan Formation, Meitan Formation, Shizipu Formation, Pagoda Formation, Linxiang Formation and Wufeng Formation from bottom to top. During the Early Ordovician Tongzi Period and Honghuayuan Period (Tremadocian Stage), a carbonate rimmed platform developed in the study area with lots of grain shoals in Guangyuan-Weiyuan Areas and Lichuan-Tongzi Areas of Southeastern Sichuan Basin. To the Meitan Period (Floian and Dapingian and Early Darriwilian Stage), a mixed carbonate platform with clastic sedimentary rock deposition developed in study area. In Middle-late Ordovician Shizipu and Linxiang-Pagoda Period (Late Darriwilian and Hirnantian-Sandbian Stage), a carbonate ramp developed in Middle-Upper Yangtze Region. At the end of the Ordovician (Hirnantian Stage), Wufeng Formation deposited in a retention basin due to the restriction of peripheral uplift and paleo-land. Two sets of reservoir-source assemblages developed in the Ordovician, with three sets of source rocks developed in the study area. First, the lower Cambrian Qiongzhusi Formation acted as the main source rock, and the hydrocarbon migrated upward to the Ordovician reservoir along the fault. Second, the Wufeng-Longmaxi Formation acted as source rock, and hydrocarbon migrated to the Lower Ordovician along the karst crust and the fault. Third, the Lower Ordovician Meitan-Shizipu Formation acted as source rock, hydrocarbon can migrate upward to the upper Ordovician reservoir directly, which deserves exploration attention.
{"title":"Lithofacies paleogeography of the Ordovician and its petroleum exploration potential in the Middle-Upper Yangtze Area, South China","authors":"Wenzheng Li , Hua Jiang , Xiaodong Fu , Yuan He , Mingfeng Gu , Nan Su , Shiyu Ma , Shugen Liu , Yongxiao Wang , Xuefei Yang","doi":"10.1016/j.petlm.2025.05.005","DOIUrl":"10.1016/j.petlm.2025.05.005","url":null,"abstract":"<div><div>Based on the drilling, logging and field analysis, this paper discusses the lithofacies paleogeography of the Ordovician and its petroleum potential in the Middle-Upper Yangtze Area, South China. Results show that Ordovician of the Middle-Upper Yangtze Region can be divided into Tongzi Formation, Honghuayuan Formation, Meitan Formation, Shizipu Formation, Pagoda Formation, Linxiang Formation and Wufeng Formation from bottom to top. During the Early Ordovician Tongzi Period and Honghuayuan Period (Tremadocian Stage), a carbonate rimmed platform developed in the study area with lots of grain shoals in Guangyuan-Weiyuan Areas and Lichuan-Tongzi Areas of Southeastern Sichuan Basin. To the Meitan Period (Floian and Dapingian and Early Darriwilian Stage), a mixed carbonate platform with clastic sedimentary rock deposition developed in study area. In Middle-late Ordovician Shizipu and Linxiang-Pagoda Period (Late Darriwilian and Hirnantian-Sandbian Stage), a carbonate ramp developed in Middle-Upper Yangtze Region. At the end of the Ordovician (Hirnantian Stage), Wufeng Formation deposited in a retention basin due to the restriction of peripheral uplift and paleo-land. Two sets of reservoir-source assemblages developed in the Ordovician, with three sets of source rocks developed in the study area. First, the lower Cambrian Qiongzhusi Formation acted as the main source rock, and the hydrocarbon migrated upward to the Ordovician reservoir along the fault. Second, the Wufeng-Longmaxi Formation acted as source rock, and hydrocarbon migrated to the Lower Ordovician along the karst crust and the fault. Third, the Lower Ordovician Meitan-Shizipu Formation acted as source rock, hydrocarbon can migrate upward to the upper Ordovician reservoir directly, which deserves exploration attention.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 440-453"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989974","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.07.007
Hongnan Yang , Ping Yue , Zhouhua Wang , Yuewen Xiong , Wei Fan , Shaoshuai Zhang , Wenxiang Shi
Understanding the flow mechanisms between hydrocarbons and interfaces in nanopores is critical for fluid supply in tight reservoirs with huge reserves. In this paper, the nanoscale liquid-solid interface interaction potential is analyzed based on the molecular interface theory, and a new nanoscale fluid viscosity model is constructed through the Eyring model, and the fluid velocity and flow flux models in nanopores are derived based on the liquid-solid interface slip condition. In addition, n-pentane flow characteristics in quartz nanopores were investigated with key parameters including: the Hamaker constant, the decay length, the wetting angle, the boundary slip and the flux coefficient. The proposed model is validated in a comparison of theory, simulation and laboratory results. The study results show: (1) influenced by the liquid-solid interfacial effect, there is a viscosity gap between the fluid in the bulk and at the boundary, resulting in a non-linear variation of the flow velocity. Of the multiple microscopic forces considered by the model, Ligshitz-Van der Waals force has the strongest effect in confined pores below 40 nm, and electrostatic force has the weakest effect. When the pore diameter less than 10 nm, the constrained fluid viscosity was improved above 4 times. (2) based on the microscopic liquid-solid interface slip condition, a constrained space velocity model is derived, which indicates that the flow is directly dependent on the effective shear stresses on the fluid and the strength of the liquid-solid interface effect. Under the low shear stress in a tight reservoir, the slip at the liquid-solid interface has obvious linear characteristics, and the slip velocity depends on the effective shear stress. The liquid-solid interfacial effect parameter is increased from 1 to 30, and the slip velocity is reduced to 3.2 Å/ps, which is a 55% reduction. (3) in this paper, the hamaker constant of n-pentane-quartz interface based on the molecular spacing variation and the decay constant for different water types and solute concentrations are obtained, and the effect of the decay length on the flow coefficient of the nano confined flow model is explored for different pore radiuses. The flux coefficient increases with pore radius, and the effect of the decay length is greater for pores <100 nm.
{"title":"Nanoscale flow model modelling and analysis of tight reservoir based on viscosity change and interfacial slip characteristics in confined space","authors":"Hongnan Yang , Ping Yue , Zhouhua Wang , Yuewen Xiong , Wei Fan , Shaoshuai Zhang , Wenxiang Shi","doi":"10.1016/j.petlm.2025.07.007","DOIUrl":"10.1016/j.petlm.2025.07.007","url":null,"abstract":"<div><div>Understanding the flow mechanisms between hydrocarbons and interfaces in nanopores is critical for fluid supply in tight reservoirs with huge reserves. In this paper, the nanoscale liquid-solid interface interaction potential is analyzed based on the molecular interface theory, and a new nanoscale fluid viscosity model is constructed through the Eyring model, and the fluid velocity and flow flux models in nanopores are derived based on the liquid-solid interface slip condition. In addition, n-pentane flow characteristics in quartz nanopores were investigated with key parameters including: the Hamaker constant, the decay length, the wetting angle, the boundary slip and the flux coefficient. The proposed model is validated in a comparison of theory, simulation and laboratory results. The study results show: (1) influenced by the liquid-solid interfacial effect, there is a viscosity gap between the fluid in the bulk and at the boundary, resulting in a non-linear variation of the flow velocity. Of the multiple microscopic forces considered by the model, Ligshitz-Van der Waals force has the strongest effect in confined pores below 40 nm, and electrostatic force has the weakest effect. When the pore diameter less than 10 nm, the constrained fluid viscosity was improved above 4 times. (2) based on the microscopic liquid-solid interface slip condition, a constrained space velocity model is derived, which indicates that the flow is directly dependent on the effective shear stresses on the fluid and the strength of the liquid-solid interface effect. Under the low shear stress in a tight reservoir, the slip at the liquid-solid interface has obvious linear characteristics, and the slip velocity depends on the effective shear stress. The liquid-solid interfacial effect parameter is increased from 1 to 30, and the slip velocity is reduced to 3.2 Å/ps, which is a 55% reduction. (3) in this paper, the hamaker constant of n-pentane-quartz interface based on the molecular spacing variation and the decay constant for different water types and solute concentrations are obtained, and the effect of the decay length on the flow coefficient of the nano confined flow model is explored for different pore radiuses. The flux coefficient increases with pore radius, and the effect of the decay length is greater for pores <100 nm.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 504-515"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989972","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.07.006
Zehua Chen , Wenjian Yue , Chao Xiong , Jingping Liu , Chengwen Wang
Phase-change material (PCM) has a high potential to cool the drilling fluids for ultra-deep oil/gas wells and geothermal wells to ensure efficient drilling and resource exploitation. Because PCM tends to agglomerate and seriously affect the properties of drilling fluid, it is necessary that the PCM is protected by a shell on its surface. In this study, a novel microencapsulated PCM (with a phase transition temperature of 130.5 °C) with a SiO2 protection shell were obtained by using tetraethyl orthosilicate (TEOS) as silicon source via a sol-gel process. PCM microcapsules with optimal synthesis ratio of 3:4 have excellent warm blood characteristics and smooth shell. The addition of 5 wt% PCM microcapsules for accurate heat trapping and temperature control at 130 °C effectively delays the time of drilling fluid reaching 150 °C by 42.5%, which improves the operability of drilling fluid at high cycle temperature. The results of this study can provide useful insights and information for use of PCM in ultra-deep oil/gas and geothermal wells.
{"title":"Phase change material microcapsules used for cooling of ultra-deep oil/gas and geothermal drilling fluids","authors":"Zehua Chen , Wenjian Yue , Chao Xiong , Jingping Liu , Chengwen Wang","doi":"10.1016/j.petlm.2025.07.006","DOIUrl":"10.1016/j.petlm.2025.07.006","url":null,"abstract":"<div><div>Phase-change material (PCM) has a high potential to cool the drilling fluids for ultra-deep oil/gas wells and geothermal wells to ensure efficient drilling and resource exploitation. Because PCM tends to agglomerate and seriously affect the properties of drilling fluid, it is necessary that the PCM is protected by a shell on its surface. In this study, a novel microencapsulated PCM (with a phase transition temperature of 130.5 °C) with a SiO<sub>2</sub> protection shell were obtained by using tetraethyl orthosilicate (TEOS) as silicon source via a sol-gel process. PCM microcapsules with optimal synthesis ratio of 3:4 have excellent warm blood characteristics and smooth shell. The addition of 5 wt% PCM microcapsules for accurate heat trapping and temperature control at 130 °C effectively delays the time of drilling fluid reaching 150 °C by 42.5%, which improves the operability of drilling fluid at high cycle temperature. The results of this study can provide useful insights and information for use of PCM in ultra-deep oil/gas and geothermal wells.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 465-474"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989969","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.07.005
Yongqiang Ren , Chen Wang , Dong Yang , Wei Zhang , Shuangyue Kou , Jinhua Mao , Qinghe Zhang , Yang Zhang , Jincheng Mao , Chong Lin , Xiaojiang Yang
Hydraulic fracturing is a critical process in oil and gas extraction, particularly in high-temperature deep and ultra-deep reservoirs where traditional polymers like partially hydrolyzed polyacrylamide (HPAM) fail due to poor heat resistance. This study introduces a novel hydrophobic associative water-soluble polymer (HAWSP), AASN, designed to overcome HPAM’s limitations. AASN is synthesized by copolymerizing a specially designed two-tailed hydrophobic monomer (C8NC12AM) with acrylamide, acrylic acid, and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), producing a polymer with excellent viscosity and thermal stability. Its unique structure, based on hydrophobic interactions among two-tailed monomers, forms a robust viscoelastic network in solution. This network is highly effective in transporting proppant during fracturing operations without the need for additional cross-linking agents, simplifying field application and reducing potential formation damage due to residue. Rheological tests show AASN maintains high viscosity and strong shear resistance at temperatures up to 140 °C. The study also examines its gel-breaking performance with different concentrations of ammonium persulfate, demonstrating easy degradation and low environmental impact after fracturing. The development of AASN significantly improves the performance of fracturing fluids and marks an important advancement in oilfield polymer technology. It offers a promising, heat-resistant alternative to current solutions, potentially transforming high-temperature hydraulic fracturing practices.
{"title":"Synthesis and characterization of a novel high temperature resistant hydrophobic associative polymer for hydraulic fracturing","authors":"Yongqiang Ren , Chen Wang , Dong Yang , Wei Zhang , Shuangyue Kou , Jinhua Mao , Qinghe Zhang , Yang Zhang , Jincheng Mao , Chong Lin , Xiaojiang Yang","doi":"10.1016/j.petlm.2025.07.005","DOIUrl":"10.1016/j.petlm.2025.07.005","url":null,"abstract":"<div><div>Hydraulic fracturing is a critical process in oil and gas extraction, particularly in high-temperature deep and ultra-deep reservoirs where traditional polymers like partially hydrolyzed polyacrylamide (HPAM) fail due to poor heat resistance. This study introduces a novel hydrophobic associative water-soluble polymer (HAWSP), AASN, designed to overcome HPAM’s limitations. AASN is synthesized by copolymerizing a specially designed two-tailed hydrophobic monomer (C<sub>8</sub>NC<sub>12</sub>AM) with acrylamide, acrylic acid, and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), producing a polymer with excellent viscosity and thermal stability. Its unique structure, based on hydrophobic interactions among two-tailed monomers, forms a robust viscoelastic network in solution. This network is highly effective in transporting proppant during fracturing operations without the need for additional cross-linking agents, simplifying field application and reducing potential formation damage due to residue. Rheological tests show AASN maintains high viscosity and strong shear resistance at temperatures up to 140 °C. The study also examines its gel-breaking performance with different concentrations of ammonium persulfate, demonstrating easy degradation and low environmental impact after fracturing. The development of AASN significantly improves the performance of fracturing fluids and marks an important advancement in oilfield polymer technology. It offers a promising, heat-resistant alternative to current solutions, potentially transforming high-temperature hydraulic fracturing practices.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 496-503"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989971","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Increasing carbon dioxide levels are significantly impacting the ecosystem, prompting the oil industry to explore innovative methods for reducing emissions and trapping CO2 while enhancing oil recovery. Among these, the water-alternating-gas CO2 (WAG-CO2) injection process has emerged as a crucial technique for optimizing hydrocarbon extraction from subsurface reservoirs. WAG-CO2 combines the benefits of water injection with the utilization of CO2, enhancing oil production efficiency and offering a potential solution for CO2 storage. This mini-review delves into the multifaceted aspects of WAG injection, including advanced variations such as surfactant alternating gas (SAG) and low-salinity water alternating gas (LS-WAG). Furthermore, it explores recent advancements in the field, such as CO2 alternating nano water (NWAG) and foam assisted WAG (FWAG) injections, underscoring the evolution of these techniques. The integration of WAG with polymer injection and mobility control technologies produces synergistic effects, expanding the applicability of WAG methods. This review provides a comprehensive analysis of the potential of WAG and its derivatives for enhanced oil recovery (EOR) while addressing current challenges and future trends, thereby contributing to the sustainable development of the oil industry.
{"title":"A mini-review of water-alternating-CO2 injection process and derivations for enhanced oil recovery and CO2 storage in subsurface reservoirs","authors":"Jaafar Ashour Abdulsada , Hailong Chen , Bing Wei , Dexin Zhang , Yousheng Fan , Yijian Ren","doi":"10.1016/j.petlm.2025.07.001","DOIUrl":"10.1016/j.petlm.2025.07.001","url":null,"abstract":"<div><div>Increasing carbon dioxide levels are significantly impacting the ecosystem, prompting the oil industry to explore innovative methods for reducing emissions and trapping CO<sub>2</sub> while enhancing oil recovery. Among these, the water-alternating-gas CO<sub>2</sub> (WAG-CO<sub>2</sub>) injection process has emerged as a crucial technique for optimizing hydrocarbon extraction from subsurface reservoirs. WAG-CO<sub>2</sub> combines the benefits of water injection with the utilization of CO<sub>2</sub>, enhancing oil production efficiency and offering a potential solution for CO<sub>2</sub> storage. This mini-review delves into the multifaceted aspects of WAG injection, including advanced variations such as surfactant alternating gas (SAG) and low-salinity water alternating gas (LS-WAG). Furthermore, it explores recent advancements in the field, such as CO<sub>2</sub> alternating nano water (NWAG) and foam assisted WAG (FWAG) injections, underscoring the evolution of these techniques. The integration of WAG with polymer injection and mobility control technologies produces synergistic effects, expanding the applicability of WAG methods. This review provides a comprehensive analysis of the potential of WAG and its derivatives for enhanced oil recovery (EOR) while addressing current challenges and future trends, thereby contributing to the sustainable development of the oil industry.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 410-421"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989967","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Enhanced oil recovery (EOR) technologies are used to recover most of the trapped crude oil from our limited reserves. With the escalating energy demand, EOR will achieve substantial economic benefits and greatly help in the exploitation of natural oil reserves. Recent research focused on microfluidic platforms for studying flow behavior during EOR flooding. These platforms are micro-sized, and allow processing and visualization of a minimal amount of fluid, making them an intriguing tool for studying the microscale phenomena in EOR processes. This review presents a comprehensive and concise literature on microfluidic trends and developments in EOR. A particular focus is on the use of these platforms to assess oil recovery via chemical-based flooding methods, to understand the associated emulsification mechanisms, and to mimic subsurface morphology and mineralogy of reservoirs. Furthermore, an outlook on the advancement of microfluidics utilization in EOR applications is discussed, covering development efficient micro-scale separators, 3D printing, and Artificial Intelligence applications. Microfluidic platforms provide valuable insights into EOR processes, and ongoing advancements in microfluidics hold the potential to enhance oil recovery efficiency and optimize EOR techniques.
{"title":"Insights into the application of microfluidic platforms in enhanced oil recovery","authors":"Fadi Dawaymeh , Elie Ayoub , Maryam Khaleel , Nahla Alamoodi","doi":"10.1016/j.petlm.2025.05.006","DOIUrl":"10.1016/j.petlm.2025.05.006","url":null,"abstract":"<div><div>Enhanced oil recovery (EOR) technologies are used to recover most of the trapped crude oil from our limited reserves. With the escalating energy demand, EOR will achieve substantial economic benefits and greatly help in the exploitation of natural oil reserves. Recent research focused on microfluidic platforms for studying flow behavior during EOR flooding. These platforms are micro-sized, and allow processing and visualization of a minimal amount of fluid, making them an intriguing tool for studying the microscale phenomena in EOR processes. This review presents a comprehensive and concise literature on microfluidic trends and developments in EOR. A particular focus is on the use of these platforms to assess oil recovery via chemical-based flooding methods, to understand the associated emulsification mechanisms, and to mimic subsurface morphology and mineralogy of reservoirs. Furthermore, an outlook on the advancement of microfluidics utilization in EOR applications is discussed, covering development efficient micro-scale separators, 3D printing, and Artificial Intelligence applications. Microfluidic platforms provide valuable insights into EOR processes, and ongoing advancements in microfluidics hold the potential to enhance oil recovery efficiency and optimize EOR techniques.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 422-439"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989968","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.06.001
Yago Ryan Pinheiro dos Santos , Igor Fernandes Gomes , Analice Lima , Marcos Allyson Felipe Rodrigues , Ernani Dias da Silva Filho , José Antonio Barbosa , Antonio Celso Dantas Antonino , Daniel Amancio Duarte , Aline Flávia Nunes Remígio Antunes
This study aimed to evaluate the effects of chemical dissolution on the properties of reservoirs by matrix acidizing, using synthetic carbonate rocks with and without fractures, prepared with limestone powder, epoxy resin (chemically inert) and fractures represented by non-woven geotextile strips positioned perpendicular to the fluid flow direction, to check their influence on the dissolution process. A system was developed using an acid injection cell to carry out acidizing tests, applying a solution of acetic acid and distilled water at constant pressure, to observe the organic acid-rock interaction for contact times of 36, 72 and 108 h. Chemical and petrophysical tests, as well as image analyses using X-ray micro-computed tomography were conducted to characterize the acidizing effects. Changes in rock properties were observed as the contact time increased, particularly the increase in porosity and permeability. Was observed the formation of CO2 and calcium acetate as reaction products between calcite and acid solution. Ramified wormhole and uniform dissolution patterns were noted; moreover, fractures influenced the dissolution in regions where they were inserted, increasing the branches present along their structure and deviating the fluid flow to a perpendicular direction to the injection direction, especially observed at 72 h, highlighting the use of geotextile as a material that reproduces the fractures' transmissivity in synthetic samples. The methodologies used contributed to presenting the effects of mineral dissolution on the properties of reservoir rocks post-stimulation, emphasizing the importance of chemical/petrophysical aspects and the contribution of fractures to better understand the matrix acidizing efficiency in field.
{"title":"Acid-rock interaction investigation and the influence of fractures during matrix acidizing in carbonate rocks","authors":"Yago Ryan Pinheiro dos Santos , Igor Fernandes Gomes , Analice Lima , Marcos Allyson Felipe Rodrigues , Ernani Dias da Silva Filho , José Antonio Barbosa , Antonio Celso Dantas Antonino , Daniel Amancio Duarte , Aline Flávia Nunes Remígio Antunes","doi":"10.1016/j.petlm.2025.06.001","DOIUrl":"10.1016/j.petlm.2025.06.001","url":null,"abstract":"<div><div>This study aimed to evaluate the effects of chemical dissolution on the properties of reservoirs by matrix acidizing, using synthetic carbonate rocks with and without fractures, prepared with limestone powder, epoxy resin (chemically inert) and fractures represented by non-woven geotextile strips positioned perpendicular to the fluid flow direction, to check their influence on the dissolution process. A system was developed using an acid injection cell to carry out acidizing tests, applying a solution of acetic acid and distilled water at constant pressure, to observe the organic acid-rock interaction for contact times of 36, 72 and 108 h. Chemical and petrophysical tests, as well as image analyses using X-ray micro-computed tomography were conducted to characterize the acidizing effects. Changes in rock properties were observed as the contact time increased, particularly the increase in porosity and permeability. Was observed the formation of CO<sub>2</sub> and calcium acetate as reaction products between calcite and acid solution. Ramified wormhole and uniform dissolution patterns were noted; moreover, fractures influenced the dissolution in regions where they were inserted, increasing the branches present along their structure and deviating the fluid flow to a perpendicular direction to the injection direction, especially observed at 72 h, highlighting the use of geotextile as a material that reproduces the fractures' transmissivity in synthetic samples. The methodologies used contributed to presenting the effects of mineral dissolution on the properties of reservoir rocks post-stimulation, emphasizing the importance of chemical/petrophysical aspects and the contribution of fractures to better understand the matrix acidizing efficiency in field.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 475-495"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989970","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study presents a novel machine learning (ML)-based approach for predicting breakdown pressure (BP) in hydraulic fracturing using experimental data. Unlike traditional analytical models that rely on simplified assumptions, ML models can capture complex nonlinear relationships between BP and its influencing factors. However, a key limitation in BP prediction stems from dataset constraints, particularly the scale differences between experimental setups and real-world formations. To mitigate these limitations, this research utilizes a unique dataset of 144 BP data points, incorporating various rock mechanical properties, injection parameters, and fluid properties. Additionally, a separate analysis of pressurization rate, based on 32 additional experimental data points, was conducted to better understand its effect on fracture initiation—an aspect often overlooked in ML-based studies. The dataset includes critical parameters such as injection rate, confining pressure, tensile strength, Young's modulus, permeability, unconfined compressive strength, Poisson's ratio, porosity, wellbore radius, and fracture geometry ratio. Five ML models—LightGBM, CatBoost, XGBoost, Kolmogorov-Arnold Network (KAN), and TabNet—were trained and evaluated. TabNet achieved the highest predictive performance (R2 = 0.94) due to its attention-based feature selection and deep-learning-based representation learning. Model performance was assessed using mean absolute error (MAE) and mean squared error (MSE) to ensure robustness. To further enhance model interpretability, SHapley Additive exPlanations (SHAP) and TabNet's attention mechanism were used to explicitly assess feature importance, providing insights into the relative influence of different parameters on BP predictions. Additionally, advanced feature-handling techniques were employed to address categorical variables automatically, ensuring minimal preprocessing bias. The findings demonstrate the scalability of ML models for BP prediction using experimental data, reducing reliance on costly and time-consuming laboratory testing. By incorporating advanced interpretability techniques, systematic pressurization rate analysis, and robust ML architectures, this research provides a more accurate, data-driven approach for optimizing hydraulic fracturing designs.
{"title":"A novel approach to modeling breakdown pressure dynamics using machine learning","authors":"Subhan Aliyev, Talal Al Shafloot, Murtada Saleh Aljawad, Abdulazeez Abdulraheem, Salaheldin Elkatatny","doi":"10.1016/j.petlm.2025.07.008","DOIUrl":"10.1016/j.petlm.2025.07.008","url":null,"abstract":"<div><div>This study presents a novel machine learning (ML)-based approach for predicting breakdown pressure (BP) in hydraulic fracturing using experimental data. Unlike traditional analytical models that rely on simplified assumptions, ML models can capture complex nonlinear relationships between BP and its influencing factors. However, a key limitation in BP prediction stems from dataset constraints, particularly the scale differences between experimental setups and real-world formations. To mitigate these limitations, this research utilizes a unique dataset of 144 BP data points, incorporating various rock mechanical properties, injection parameters, and fluid properties. Additionally, a separate analysis of pressurization rate, based on 32 additional experimental data points, was conducted to better understand its effect on fracture initiation—an aspect often overlooked in ML-based studies. The dataset includes critical parameters such as injection rate, confining pressure, tensile strength, Young's modulus, permeability, unconfined compressive strength, Poisson's ratio, porosity, wellbore radius, and fracture geometry ratio. Five ML models—LightGBM, CatBoost, XGBoost, Kolmogorov-Arnold Network (KAN), and TabNet—were trained and evaluated. TabNet achieved the highest predictive performance (<em>R</em><sup>2</sup> = 0.94) due to its attention-based feature selection and deep-learning-based representation learning. Model performance was assessed using mean absolute error (MAE) and mean squared error (MSE) to ensure robustness. To further enhance model interpretability, SHapley Additive exPlanations (SHAP) and TabNet's attention mechanism were used to explicitly assess feature importance, providing insights into the relative influence of different parameters on BP predictions. Additionally, advanced feature-handling techniques were employed to address categorical variables automatically, ensuring minimal preprocessing bias. The findings demonstrate the scalability of ML models for BP prediction using experimental data, reducing reliance on costly and time-consuming laboratory testing. By incorporating advanced interpretability techniques, systematic pressurization rate analysis, and robust ML architectures, this research provides a more accurate, data-driven approach for optimizing hydraulic fracturing designs.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 516-532"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989973","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-08-01DOI: 10.1016/j.petlm.2025.07.003
Dongdong Guo , Jiaxin Sun , Bing Liu , Hengyin Zhu , Ren Wang , Fulong Ning
Well drilling operations are essential for the exploration and development of natural gas hydrates. However, under specific conditions, drilling fluids can invade reservoirs, leading to borehole instability and distortions in well-logging data. The incorporation of nanoparticles has proven to be an effective method to enhance the anti-filtration and pore or fracture plugging capabilities of drilling fluids, thus improving wellbore stability. Additionally, research has shown that a targeted concentration of hydrophilic nanoparticles can inhibit hydrate formation. This study focuses on hydrophilic nano-CaCO3 particles as specialized additives for drilling fluids and proposes a nano-based hydrate drilling fluid system. The performance and hydrate inhibition of this modified drilling fluid were comprehensively evaluated. The designed formulation for the simulated drilling fluid was determined to be: 1.0% CMC + 0.1% PAM + 0.1% XC + 5.0% NaCl + 5.0% KCl + 1.0% PVCap + 1.0%–6.0% nano-CaCO3. The designed drilling fluid system achieved a colloidal stability exceeding 97%, with a density range of 1.08–1.10 g/cm3. Its apparent viscosity ranged from 36 to 79.5 mPa·s, plastic viscosity from 27 to 42 mPa·s, and dynamic shear force from 8.176 to 38.325 Pa. The rheological effects of nanoparticles are concentration-dependent, with minimal changes at 1–4 wt% and significant increases at 5–6 wt%, enabling performance tuning for drilling needs. The pH value of the fluid was approximately 7, which could be modified by the addition of alkaline substances. Furthermore, as the nanoparticle concentration increased, the fluid's filtration rate progressively decreased. Therefore, this nano-CaCO3-based drilling fluid system demonstrates excellent reservoir protection properties and is well-suited for drilling in marine hydrate-bearing sediments.
{"title":"Design and performance evaluation of nano-based drilling fluid system for hydrate bearing sediments","authors":"Dongdong Guo , Jiaxin Sun , Bing Liu , Hengyin Zhu , Ren Wang , Fulong Ning","doi":"10.1016/j.petlm.2025.07.003","DOIUrl":"10.1016/j.petlm.2025.07.003","url":null,"abstract":"<div><div>Well drilling operations are essential for the exploration and development of natural gas hydrates. However, under specific conditions, drilling fluids can invade reservoirs, leading to borehole instability and distortions in well-logging data. The incorporation of nanoparticles has proven to be an effective method to enhance the anti-filtration and pore or fracture plugging capabilities of drilling fluids, thus improving wellbore stability. Additionally, research has shown that a targeted concentration of hydrophilic nanoparticles can inhibit hydrate formation. This study focuses on hydrophilic nano-CaCO<sub>3</sub> particles as specialized additives for drilling fluids and proposes a nano-based hydrate drilling fluid system. The performance and hydrate inhibition of this modified drilling fluid were comprehensively evaluated. The designed formulation for the simulated drilling fluid was determined to be: 1.0% CMC + 0.1% PAM + 0.1% XC + 5.0% NaCl + 5.0% KCl + 1.0% PVCap + 1.0%–6.0% nano-CaCO<sub>3</sub>. The designed drilling fluid system achieved a colloidal stability exceeding 97%, with a density range of 1.08–1.10 g/cm<sup>3</sup>. Its apparent viscosity ranged from 36 to 79.5 mPa·s, plastic viscosity from 27 to 42 mPa·s, and dynamic shear force from 8.176 to 38.325 Pa. The rheological effects of nanoparticles are concentration-dependent, with minimal changes at 1–4 wt% and significant increases at 5–6 wt%, enabling performance tuning for drilling needs. The pH value of the fluid was approximately 7, which could be modified by the addition of alkaline substances. Furthermore, as the nanoparticle concentration increased, the fluid's filtration rate progressively decreased. Therefore, this nano-CaCO<sub>3</sub>-based drilling fluid system demonstrates excellent reservoir protection properties and is well-suited for drilling in marine hydrate-bearing sediments.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 4","pages":"Pages 454-464"},"PeriodicalIF":3.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989975","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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