Developing low-permeability Coalbed Methane(CBM)reservoirs can significantly benefit from a comprehensive understanding of hydraulic fracture nucleation and propagation mechanisms,particularly in anthracite CBM reserv...Developing low-permeability Coalbed Methane(CBM)reservoirs can significantly benefit from a comprehensive understanding of hydraulic fracture nucleation and propagation mechanisms,particularly in anthracite CBM reservoirs.This study employs true-triaxial hydraulic fracturing experiments to investigate these mechanisms,with variables including injection flow rate,horizontal stress difference(σH-σh),and bedding orientation.Additionally,we conduct corresponding numerical cases to validate the experimental conclusions.The research also considers re-fracturing instances.For the first time,we utilize a combination of Kaiser tests and the stress transfer function in ANSYS Workbench finite element analysis to accurately restore the confining pressure of the coal sample.The findings suggest that a high initial injection flow rate during hydraulic fracturing can promote fluid leakage and aid in maintaining substantial fracture pressure.Enhanced fracturing efficiency can be achieved through higher injection rates,and it can ensure optimal fracturing efficiency,minimizing roof and floor fracturing in coal reservoirs to prevent fracturing fluid leakage.The presence of a high horizontal stress difference facilitates hydraulic fracture propagation along the direction of the maximum horizontal compressive stress,requiring a greater hydraulic pressure to produce more fracture systems in coal reservoirs.Additionally,a minor deviation in the wellbore injection direction from the bedding orientation assists in creating a complex hydraulic fractured network,although this also requires higher hydraulic pressure to initiate new fractures.In the case of multiple hydraulic fracturing,the second initiation pressure tends to be significantly higher than the first,indicating that a sequential increase in hydraulic pressure aids the formation of additional fractures.Moreover,a simplified numerical simulation has been conducted to corroborate the experimental findings.These insights are crucial in optimizing hydraulic fracturing processes to enhance the permeability of anthracite CBM reservoirs.展开更多
Carbon capture and storage(CCS)has been proposed as a potential technology to mitigate climate change.However,there is currently a huge gap between the current global deployment of this technology and that which will ...Carbon capture and storage(CCS)has been proposed as a potential technology to mitigate climate change.However,there is currently a huge gap between the current global deployment of this technology and that which will be ultimately required.Whilst CO2 can be captured at any geographic location,storage of CO2 will be constrained by the geological storage potential in the area the CO2 is captured.The geological storage potential can be evaluated at a very high level according to the tectonic setting of the target area.To date,CCS deployment has been restricted to more favourable tectonic settings,such as extensional passive margin and post-rift basins and compressional foreland basins.However,to reach the adequate level of deployment,the potential for CCS of regions in different tectonic settings needs to be explored and assessed worldwide.Surprisingly,the potential of compressional basins for carbon storage has not been universally evaluated according to the global and regional carbon emission distribution.Here,we present an integrated source-to-sink analysis tool that combines comprehensive,open-access information on basin distribution,hydrocarbon resources and CO2 emissions based on geographical information systems(GIS).Compressional settings host some of the most significant hydrocarbon-bearing basins and 36% of inland CO2 emissions but,to date,large-scale CCS facilities in compressional basins are concentrated in North America and the Middle East only.Our source-to-sink tool allows identifying five high-priority regions for prospective CCS development in compressional basins:North America,north-western South America,south-eastern Europe,the western Middle East and western China.We present a study of the characteristics of these areas in terms of CO2 emissions and CO2 storage potential.Additionally,we conduct a detailed case-study analysis of the Sichuan Basin(China),one of the compressional basins with the greatest CO2 storage potential.Our results indicate that compressional basins will have to play a critical role in the future of CCS if this technology is to be implemented worldwide.展开更多
It is not uncommon to observe shear fractures in ductile rocks oriented at more than 45° with respect to the maximum compression direction. Since these orientations cannot be explained with the classic Mohr-Coulu...It is not uncommon to observe shear fractures in ductile rocks oriented at more than 45° with respect to the maximum compression direction. Since these orientations cannot be explained with the classic Mohr-Coulumb or Tresca yield criteria, Zheng et al.(Journal of Structural Geology, 35: 1394–1405, 2011) proposed the maximum effective moment(MEM) failure criterion. This rule suggests that shear fractures in ductile rocks form at ?55° with the maximum compression axis and that this orientation is material-independent and, therefore, universal. Zheng et al.(Science China: Earth Sciences, 57(11): 2819–2824, 2014) used data from our own experiments as supporting evidence of their failure criterion. In this contribution we discuss why shear fracture formation in ductile rocks indeed strongly depends on the mechanical properties of the deforming medium, and why experimental data should not be taken to prove the validity of the MEM criterion. The formation mechanisms and orientations of shear fractures in our experiments significantly vary depending on the material strength and degree and type of anisotropy(composite and intrinsic). We therefore demonstrate using experimental data that a universal failure angle in ductile and anisotropic rocks does not apply. Additionally, we highlight some inconsistencies of the MEM criterion.展开更多
Natural fractures are of crucial importance for oil and gas reservoirs,especially for those with ultralow permeability and porosity.The deep-marine shale gas reservoirs of the Wufeng and Longmaxi Formations are typica...Natural fractures are of crucial importance for oil and gas reservoirs,especially for those with ultralow permeability and porosity.The deep-marine shale gas reservoirs of the Wufeng and Longmaxi Formations are typical targets for the study of natural fracture characteristics.Detailed descriptions of full-diameter shale drill core,together with 3D Computed Tomography scans and Formation MicroScanner Image data acquisition,were carried out to characterize microfracture morphology in order to obtain the key parameters of natural fractures in such system.The fracture type,orientation,and their macroscopic and microscopic distribution features are evaluated.The results show that the natural fracture density appears to remarkably decrease in the Wufeng and Longmaxi Formations with increasing the burial depth.Similar trends have been observed for fracture length and aperture.Moreover,the natural fracture density diminishes as the formation thickness increases.There are three main types of natural fractures,which we interpret as(I)mineral-filled fractures(by pyrite and calcite),i.e.,veins,(II)those induced by tectonic stress,and(III)those formed by other processes(including diagenetic shrinkage and fluid overpressure).Natural fracture orientations estimated from the studied natural fractures in the Luzhou block are not consistent with the present-day stress field.The difference in tortuosity between horizontally and vertically oriented fractures reveals their morphological complexity.In addition,natural fracture density,host rock formation thickness,average total organic carbon and effective porosity are found to be important factors for evaluating shale gas reservoirs.The study also reveals that the high density of natural fractures is decisive to evaluate the shale gas potential.The results may have significant implications for evaluating favorable exploration areas of shale gas reservoirs and can be applied to optimize hydraulic fracturing for permeability enhancement.展开更多
基金funded by the National Natural Science Foundation of China(No.42202155)China Postdoctoral Science Foundation(No.2021MD703807)+7 种基金Heilongjiang Provincial Postdoctoral Science Foundation(No.LBH-Z20121)financial support from the China Scholarship Council(No.202008230018)the Research Fund Program of Hubei Key Laboratory of Resources and Eco-Environment Geology(No.HBREGKFJJ-202309)funding by the DGICYT Spanish Project(grant no.PID2020-118999GB-I00)funded by the MCIN/AEI/10.13039/501100011033funding by the Ramón y Cajal fellowship(grant no.RyC-2018-026335-I)funded by the MCIN/AEI/10.13039/50110001103the European Social Fund-Investing in Your Future.
文摘Developing low-permeability Coalbed Methane(CBM)reservoirs can significantly benefit from a comprehensive understanding of hydraulic fracture nucleation and propagation mechanisms,particularly in anthracite CBM reservoirs.This study employs true-triaxial hydraulic fracturing experiments to investigate these mechanisms,with variables including injection flow rate,horizontal stress difference(σH-σh),and bedding orientation.Additionally,we conduct corresponding numerical cases to validate the experimental conclusions.The research also considers re-fracturing instances.For the first time,we utilize a combination of Kaiser tests and the stress transfer function in ANSYS Workbench finite element analysis to accurately restore the confining pressure of the coal sample.The findings suggest that a high initial injection flow rate during hydraulic fracturing can promote fluid leakage and aid in maintaining substantial fracture pressure.Enhanced fracturing efficiency can be achieved through higher injection rates,and it can ensure optimal fracturing efficiency,minimizing roof and floor fracturing in coal reservoirs to prevent fracturing fluid leakage.The presence of a high horizontal stress difference facilitates hydraulic fracture propagation along the direction of the maximum horizontal compressive stress,requiring a greater hydraulic pressure to produce more fracture systems in coal reservoirs.Additionally,a minor deviation in the wellbore injection direction from the bedding orientation assists in creating a complex hydraulic fractured network,although this also requires higher hydraulic pressure to initiate new fractures.In the case of multiple hydraulic fracturing,the second initiation pressure tends to be significantly higher than the first,indicating that a sequential increase in hydraulic pressure aids the formation of additional fractures.Moreover,a simplified numerical simulation has been conducted to corroborate the experimental findings.These insights are crucial in optimizing hydraulic fracturing processes to enhance the permeability of anthracite CBM reservoirs.
基金the framework of DGICYT Spanish Projects CGL2015-66335-C2-1-R and PGC2018-093903-B-C22Grup Consolidat de Recerca“Geologia Sedimentaria”(2017-SGR-824)+5 种基金funded by the China Scholarship Council(CSC)(201806450043)JA received funding by EIT Raw Materials–SIT4ME Project(17024)funded by MICINN(Juan de la Cierva fellowship-IJC2018-036074-I)funding by the AGAUR(Agencia de Gestio d’Ajuts Universitaris i de Recerca)of the Generalitat de Catalunya(“Beatriu de Pinos”fellowship 2017SGR-824)the Spanish Ministry of Science,Innovation and Universities(“Ramon y Cajal”fellowship RYC2018-026335-I)funded by the University of Strathclyde Faculty of Engineering。
文摘Carbon capture and storage(CCS)has been proposed as a potential technology to mitigate climate change.However,there is currently a huge gap between the current global deployment of this technology and that which will be ultimately required.Whilst CO2 can be captured at any geographic location,storage of CO2 will be constrained by the geological storage potential in the area the CO2 is captured.The geological storage potential can be evaluated at a very high level according to the tectonic setting of the target area.To date,CCS deployment has been restricted to more favourable tectonic settings,such as extensional passive margin and post-rift basins and compressional foreland basins.However,to reach the adequate level of deployment,the potential for CCS of regions in different tectonic settings needs to be explored and assessed worldwide.Surprisingly,the potential of compressional basins for carbon storage has not been universally evaluated according to the global and regional carbon emission distribution.Here,we present an integrated source-to-sink analysis tool that combines comprehensive,open-access information on basin distribution,hydrocarbon resources and CO2 emissions based on geographical information systems(GIS).Compressional settings host some of the most significant hydrocarbon-bearing basins and 36% of inland CO2 emissions but,to date,large-scale CCS facilities in compressional basins are concentrated in North America and the Middle East only.Our source-to-sink tool allows identifying five high-priority regions for prospective CCS development in compressional basins:North America,north-western South America,south-eastern Europe,the western Middle East and western China.We present a study of the characteristics of these areas in terms of CO2 emissions and CO2 storage potential.Additionally,we conduct a detailed case-study analysis of the Sichuan Basin(China),one of the compressional basins with the greatest CO2 storage potential.Our results indicate that compressional basins will have to play a critical role in the future of CCS if this technology is to be implemented worldwide.
文摘It is not uncommon to observe shear fractures in ductile rocks oriented at more than 45° with respect to the maximum compression direction. Since these orientations cannot be explained with the classic Mohr-Coulumb or Tresca yield criteria, Zheng et al.(Journal of Structural Geology, 35: 1394–1405, 2011) proposed the maximum effective moment(MEM) failure criterion. This rule suggests that shear fractures in ductile rocks form at ?55° with the maximum compression axis and that this orientation is material-independent and, therefore, universal. Zheng et al.(Science China: Earth Sciences, 57(11): 2819–2824, 2014) used data from our own experiments as supporting evidence of their failure criterion. In this contribution we discuss why shear fracture formation in ductile rocks indeed strongly depends on the mechanical properties of the deforming medium, and why experimental data should not be taken to prove the validity of the MEM criterion. The formation mechanisms and orientations of shear fractures in our experiments significantly vary depending on the material strength and degree and type of anisotropy(composite and intrinsic). We therefore demonstrate using experimental data that a universal failure angle in ductile and anisotropic rocks does not apply. Additionally, we highlight some inconsistencies of the MEM criterion.
基金The project is funded by the National Natural Science Foundation of China(Grant No.42202155)China Postdoctoral Science Foundation(No.2021MD703807),Major Special Project of the Ministry of Science and Technology of PetroChina(Nos.2022DJ8004 and 2021DJ1901)+4 种基金Heilongjiang Postdoctoral Foundation(No.LBH-Z20121)Natural Science Foundation of Hubei Province Project(No.2020CFB501)The Scientific Research Project of Department of Natural Resources of Hubei Province(No.ZRZY2020KJ10)The authors gratefully acknowledge financial support from the China Scholarship Council(No.202008230018)EGR acknowledges funding by the Spanish Ministry of Science and Innovation(MCIN)/State Research Agency of Spain(AEI)/European Regional Development Fund(ERDF)/10.13039/501100011033 for the“Ramón y Cajal”fellowship RYC2018-026335-I and research projects PGC2018-093903-B-C22 and PID2020-118999GB-I00.
文摘Natural fractures are of crucial importance for oil and gas reservoirs,especially for those with ultralow permeability and porosity.The deep-marine shale gas reservoirs of the Wufeng and Longmaxi Formations are typical targets for the study of natural fracture characteristics.Detailed descriptions of full-diameter shale drill core,together with 3D Computed Tomography scans and Formation MicroScanner Image data acquisition,were carried out to characterize microfracture morphology in order to obtain the key parameters of natural fractures in such system.The fracture type,orientation,and their macroscopic and microscopic distribution features are evaluated.The results show that the natural fracture density appears to remarkably decrease in the Wufeng and Longmaxi Formations with increasing the burial depth.Similar trends have been observed for fracture length and aperture.Moreover,the natural fracture density diminishes as the formation thickness increases.There are three main types of natural fractures,which we interpret as(I)mineral-filled fractures(by pyrite and calcite),i.e.,veins,(II)those induced by tectonic stress,and(III)those formed by other processes(including diagenetic shrinkage and fluid overpressure).Natural fracture orientations estimated from the studied natural fractures in the Luzhou block are not consistent with the present-day stress field.The difference in tortuosity between horizontally and vertically oriented fractures reveals their morphological complexity.In addition,natural fracture density,host rock formation thickness,average total organic carbon and effective porosity are found to be important factors for evaluating shale gas reservoirs.The study also reveals that the high density of natural fractures is decisive to evaluate the shale gas potential.The results may have significant implications for evaluating favorable exploration areas of shale gas reservoirs and can be applied to optimize hydraulic fracturing for permeability enhancement.
