This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis,numerical simulation,and economic evaluation.A total numbe...This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis,numerical simulation,and economic evaluation.A total number of 108 relative-permeability curves of rock samples from tight reservoirs were obtained,and the characteristics of relative-permeability curves were analyzed.The irreducible water saturation(Swi)mainly ranges from 20% to 70%,and the residual gas saturation(Sgr)ranges from 5% to 15% for 55% of the samples.The relative-permeability curves are categorized into six types(Category-Ⅰ to Ⅵ)by analyzing the following characteristics:The relative permeability of gas at Swi,the relative permeability of water at Sgr,and the relative permeability corresponding to the isotonic point.The relative permeability curves were normalized to facilitate numerical simulation and evaluate the impact of different types of curves on production performance.The results of simulation show significant difference in production performance for different types of relative-permeability curves:Category-Ⅰ corresponds to the case with best well performance,whereas Categories-Ⅴ and Ⅵ correspond to the cases with least production volume.The results of economic evaluation show a generalized permeability jail for Categories-Ⅳ,Ⅴ,and Ⅵ,and the permeability jail develops when the relative permeability of gas and water is below 0.06.This study further quantifies the range of micro-pore parameters corresponding to the generalized permeability jail for a tight sandstone reservoir.展开更多
The main methods of coalbed methane(CBM)development are drainage and depressurization,and a precise prediction of coal reservoir pressure is thus crucial for the evaluation of reservoir potentials and the formulation ...The main methods of coalbed methane(CBM)development are drainage and depressurization,and a precise prediction of coal reservoir pressure is thus crucial for the evaluation of reservoir potentials and the formulation of reasonable development plans.This work established a new reservoir pressure prediction model based on the material balance equation(MBE)of coal reservoir,which considers the self-regulating effects of coal reservoirs and the dynamic change of equivalent drainage area(EDA).According to the proposed model,the reservoir pressure can be predicted based on reservoir condition data and the actual production data of a single well.Compared with traditional reservoir pressure prediction models which regard EDA as a fixed value,the proposed model can better predict the average pressure of reservoirs.Moreover,orthogonal experiments were designed to evaluate the sensitivity of reservoir parameters on the reservoir pressure prediction results of this proposed model.The results show that the saturation of irreducible water is the most sensitive parameter,followed by Langmuir volume and reservoir porosity,and Langmuir pressure is the least sensitive parameter.In addition,the pressure drop of reservoirs is negatively correlated with the saturation of irreducible water and the Langmuir volume,while it is positively correlated with porosity.This work analyzed the reservoir pressure drop characteristics of the CBM wells in the Shizhuangnan Block of the Qinshui Basin,and the results show that the CBM reservoir depressurization can be divided into three types,i.e.,rapidly drop type,medium-term stability type,and slowly drop type.The drainage features of wells were reasonably interpreted based on the comprehensive analysis of the reservoir depressurization type;the latter was coupled to the corresponding permeability dynamic change characteristics,eventually proving the applicability of the proposed model.展开更多
The Lower Cretaceous Yingcheng Formation continental organic-rich shale from Lishu Depression(LSD)of the southern Songliao Basin located in northeast China has significant shale gas potential by geochemistry and petro...The Lower Cretaceous Yingcheng Formation continental organic-rich shale from Lishu Depression(LSD)of the southern Songliao Basin located in northeast China has significant shale gas potential by geochemistry and petrology.The organic-rich shale contains kerogen type II and III,and has a total organic carbon(TOC)content of 1.5wt.%.The random vitrinite reflectance(Ro,m>2.0%)is展开更多
The meandering channel deposit of the upper member of Neogene Guantao Formation in Shengli Chengdao extra-shallow sea oilfield is characterized by rapid change in sedimentary facies.In addition,affected by surface tid...The meandering channel deposit of the upper member of Neogene Guantao Formation in Shengli Chengdao extra-shallow sea oilfield is characterized by rapid change in sedimentary facies.In addition,affected by surface tides and sea water reverberation,the double sensor seismic data processed by conventional methods has low signal-to-noise ratio and low resolution,and thus cannot meet the needs of seismic description and oil-bearing fluid identification of thin reservoirs less than 10 meters thick in this area.The two-step high resolution frequency bandwidth expanding processing technology was used to improve the signal-to-noise ratio and resolution of the seismic data,as a result,the dominant frequency of the seismic data was enhanced from 30 Hz to 50 Hz,and the sand body thickness resolution was enhanced from 10 m to 6 m.On the basis of fine layer control by seismic data,three types of seismic facies models,floodplain,natural levee and point bar,were defined,and the intelligent horizon-facies controlled recognition technology was worked out,which had a prediction error of reservoir thickness of less than 1.5 m.Clearly,the description accuracy of meandering channel sand bodies has been improved.The probability semi-quantitative oiliness identification method of fluid by prestack multi-parameters has been worked out by integrating Poisson’s ratio,fluid factor,product of Lame parameter and density,and other prestack elastic parameters,and the method has a coincidence rate of fluid identification of more than 90%,providing solid technical support for the exploration and development of thin reservoirs in Shengli Chengdao extra-shallow sea oilfield,which is expected to provide reference for the exploration and development of similar oilfields in China.展开更多
In long-term water drive reservoir, small dose and short radius profile control cannot meet the needs, so deep profile control and flooding are needed. During the placement and processing of conventional deep profile ...In long-term water drive reservoir, small dose and short radius profile control cannot meet the needs, so deep profile control and flooding are needed. During the placement and processing of conventional deep profile control and flooding agent, the zone classification formed by the changes of pressure field and fluid field are not taken into account. In order to better develop these reservoirs, we proposed a novel deep profile control method, that is, the iso-pressure drop gradient progressive deep profile control method. The key features of the method include: 1) the method took into account the reservoir pressure distribution;2) it proposed a novel standard to divide the orders of zone;3) the method has been successfully applied in 4 wells in China Oilfield. The method divided the formation into near wellbore zone, well-far zone and deep zone according to the drawdown curve. As each zone of the pressure gradient is different and therefore require different intensity of slug. Then design the agent slugs according to iso-pressure drop gradient rule, and the breakthrough pressure gradient of agent is equal to the formation pressure gradient, and it achieved the fluid diversion of whole course by combining the different intensity of blocking agent. The method was applied successfully in 2 wells in China Oilfield from May to November in 2008. The method can smartly improve the sweep efficiency, and field test shows that it can play a very good efficiency of reducing water and increasing oil production. This method is becoming more of a concern in the oilfield develop.展开更多
The geochemical signatures of fifty-four rock samples and three supplementary drill stem test(DST)oils from the Yacheng-Sanya formations in the central Qiongdongnan Basin(CQB)were analysed.Reconstruction of the early ...The geochemical signatures of fifty-four rock samples and three supplementary drill stem test(DST)oils from the Yacheng-Sanya formations in the central Qiongdongnan Basin(CQB)were analysed.Reconstruction of the early Oligocene-early Miocene(36–16 Ma)palaeovegetation and source analyses of organic matter(OM)were conducted using aliphatic biomarkers in ancient sediments and DST oils.Both the interpreted aquatic and terrigenous OM contributed to the CQB source rocks(SRs)but had varying relative proportions.The four distribution patterns derived from n-alkanes,terpanes,and steranes are representative of four OM composition models of the Yacheng-Sanya SRs,including model A,model B,model C,and model D,which were classified based on the increasing contribution from terrigenous OM relative to aquatic OM.Some terrigenous higher plantderived biomarkers,including oleanane,des-A-oleanane,C_(29)ααα20R sterane,bicadinanes,the C_(19)/(C_(19)+C_(23))tricyclic terpane ratio,and other n-alkane-derived ratios suggest that angiosperms had increased proportions in the palaeoflora from early Oligocene to early Miocene,and the bloom of terrigenous higher plants was observed during deposition of upper Lingshui Formation to lower Sanya Formation.These findings are consistent with the incremental total organic carbon and free hydrocarbons+potential hydrocarbons(S_1+S_2)in the lower Lingshuilower Sanya strata with a significant enrichment of OM in the E_3l_1-N_1s_2 shales.The maturity-and environmentsensitive aliphatic parameters of the CQB SRs and DST oils suggest that all the samples have predominantly reached their early oil-generation windows but have not exceeded the peak oil windows,except for some immature Sanya Formation shales.In addition,most of the OM in the analysed samples was characterised by mixed OM contributions under anoxic to sub-anoxic conditions.Furthermore,terrestrial-dominant SRs were interpreted to have developed mainly in the Lingshui-Sanya formations and were deposited in sub-oxic to oxic environments,compared to the anoxic to sub-anoxic conditions of the Yacheng Formation.展开更多
With the deepening of coalbed methane(CBM)exploration and development,the problem of low gas production has gradually become one of the main factors restricting the development of the CBM industry in China.Reasonable ...With the deepening of coalbed methane(CBM)exploration and development,the problem of low gas production has gradually become one of the main factors restricting the development of the CBM industry in China.Reasonable well pattern deployment can improve the productivity of CBM wells and reduce the cost of production,while the reservoir changes of CBM wells play a important role for well pattern infilling.In this study,the dynamic characteristics of the average reservoir pressure(ARP),permeability,and drainage radius during the development process of CBM wells are systematically analyzed,and predicted the production changes of well groups before and after infilling wells in combination with the characteristics of reservoir changes.The results show that the high gas production wells have a larger pressure drop,long drainage radius,and a large increase in permeability.On the contrary,low gas production wells are characterized by small drainage radius,damaged permeability and difficult to recover.The productivity of infilled horizontal wells is predicted for two well groups with different productivity and reservoir dynamic characteristics.After infilling wells,the production of current wells has increased at different degrees.It is predicted that the average gas production of low gas production well group H1 and middle gas production well group H2 will increase 1.64 and 2.09 times respectively after 3000 days production simulation.In addition,the pressure interference between wells has increased significantly,and the overall gas production of the well group has greatly increased.Infill wells can achieve better development results in areas with superior CBM resources,recoverable reservoir permeability,and small drainage radius during the early production process.The research results provide a reference for the later infill adjustment of CBM well patterns in the study area.展开更多
In this paper, the analysis of faults with different scales and orientations reveals that the distribution of fractures always develops toward a higher degree of similarity with faults, and a method for calculating th...In this paper, the analysis of faults with different scales and orientations reveals that the distribution of fractures always develops toward a higher degree of similarity with faults, and a method for calculating the multiscale areal fracture density is proposed using fault-fracture self-similarity theory. Based on the fracture parameters observed in cores and thin sections, the initial apertures of multiscale fractures are determined using the constraint method with a skewed distribution. Through calculations and statistical analyses of in situ stresses in combination with physical experiments on rocks, a numerical geomechanical model of the in situ stress field is established. The fracture opening ability under the in situ stress field is subsequently analyzed. Combining the fracture aperture data and areal fracture density at different scales, a calculation model is proposed for the prediction of multiscale and multiperiod fracture parameters, including the fracture porosity, the magnitude and direction of maximum permeability and the flow conductivity. Finally, based on the relationships among fracture aperture,density, and the relative values of fracture porosity and permeability, a fracture development pattern is determined.展开更多
Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water dis...Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water distribution in rocks during imbibition using various nanofluids was less discussed in previous studies.In this study,we systematically examined the imbibition efficiencies of various nanofluids at60℃.Furthermore,the migration of nanofluids and oil distribution in the rock pores were monitored using nuclear magnetic resonance(NMR).The nanofluids were prepared by dispersing silica nanoparticles and five different types of surfactants i.e.,anionic-nonionic,anionic,nonionic,amphoteric and cationic surfactants in deionized(DI)water.Subsequently,interfacial tension(IFT)and contact angle measurements were conducted to reveal the underlying EOR mechanisms of various nanofluids.The experimental results showed that the EOR potential of the different types of nanofluids was in the order anionic-nonionic>anionic>nonionic>amphoteric>cationic>brine.Anionic-nonionic(sodium lauryl ether sulfate(SLES))and anionic(sodium dodecyl sulfonate(SDS))nanofluids exhibited excellent capability of wettability alteration,and increased oil recovery by 27.96%and 23.08%,respectively,compared to brine.The NMR results also showed that mesopores(0.1-1μm)were the dominant developed pores in the rocks,and contributed the most to imbibition efficiency.In addition,the imbibition of nanofluids initially took place in mesopores and micropores before moving into macropores.This study provides fundamental information on the selection of nanofluids for EOR in tight oil reservoirs.The study also improved the understanding of oil/water distribution during the imbibition of the proposed nanofluids.展开更多
基金the financial support from the National Natural Science Foundation of China(No.51774255 and 52174037).
文摘This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis,numerical simulation,and economic evaluation.A total number of 108 relative-permeability curves of rock samples from tight reservoirs were obtained,and the characteristics of relative-permeability curves were analyzed.The irreducible water saturation(Swi)mainly ranges from 20% to 70%,and the residual gas saturation(Sgr)ranges from 5% to 15% for 55% of the samples.The relative-permeability curves are categorized into six types(Category-Ⅰ to Ⅵ)by analyzing the following characteristics:The relative permeability of gas at Swi,the relative permeability of water at Sgr,and the relative permeability corresponding to the isotonic point.The relative permeability curves were normalized to facilitate numerical simulation and evaluate the impact of different types of curves on production performance.The results of simulation show significant difference in production performance for different types of relative-permeability curves:Category-Ⅰ corresponds to the case with best well performance,whereas Categories-Ⅴ and Ⅵ correspond to the cases with least production volume.The results of economic evaluation show a generalized permeability jail for Categories-Ⅳ,Ⅴ,and Ⅵ,and the permeability jail develops when the relative permeability of gas and water is below 0.06.This study further quantifies the range of micro-pore parameters corresponding to the generalized permeability jail for a tight sandstone reservoir.
基金financially supported by the National Natural Science Foundation of China (grants No. 41772159/D0208, No. 41872178)the National Science and Technology Major Project of China (grant No. 2017ZX05064003)
文摘The main methods of coalbed methane(CBM)development are drainage and depressurization,and a precise prediction of coal reservoir pressure is thus crucial for the evaluation of reservoir potentials and the formulation of reasonable development plans.This work established a new reservoir pressure prediction model based on the material balance equation(MBE)of coal reservoir,which considers the self-regulating effects of coal reservoirs and the dynamic change of equivalent drainage area(EDA).According to the proposed model,the reservoir pressure can be predicted based on reservoir condition data and the actual production data of a single well.Compared with traditional reservoir pressure prediction models which regard EDA as a fixed value,the proposed model can better predict the average pressure of reservoirs.Moreover,orthogonal experiments were designed to evaluate the sensitivity of reservoir parameters on the reservoir pressure prediction results of this proposed model.The results show that the saturation of irreducible water is the most sensitive parameter,followed by Langmuir volume and reservoir porosity,and Langmuir pressure is the least sensitive parameter.In addition,the pressure drop of reservoirs is negatively correlated with the saturation of irreducible water and the Langmuir volume,while it is positively correlated with porosity.This work analyzed the reservoir pressure drop characteristics of the CBM wells in the Shizhuangnan Block of the Qinshui Basin,and the results show that the CBM reservoir depressurization can be divided into three types,i.e.,rapidly drop type,medium-term stability type,and slowly drop type.The drainage features of wells were reasonably interpreted based on the comprehensive analysis of the reservoir depressurization type;the latter was coupled to the corresponding permeability dynamic change characteristics,eventually proving the applicability of the proposed model.
文摘The Lower Cretaceous Yingcheng Formation continental organic-rich shale from Lishu Depression(LSD)of the southern Songliao Basin located in northeast China has significant shale gas potential by geochemistry and petrology.The organic-rich shale contains kerogen type II and III,and has a total organic carbon(TOC)content of 1.5wt.%.The random vitrinite reflectance(Ro,m>2.0%)is
基金Supported by the China National Science and Technology Major Project(2016zx05006)Sinopec Program for Science and Technology Development(P15156,P15159)。
文摘The meandering channel deposit of the upper member of Neogene Guantao Formation in Shengli Chengdao extra-shallow sea oilfield is characterized by rapid change in sedimentary facies.In addition,affected by surface tides and sea water reverberation,the double sensor seismic data processed by conventional methods has low signal-to-noise ratio and low resolution,and thus cannot meet the needs of seismic description and oil-bearing fluid identification of thin reservoirs less than 10 meters thick in this area.The two-step high resolution frequency bandwidth expanding processing technology was used to improve the signal-to-noise ratio and resolution of the seismic data,as a result,the dominant frequency of the seismic data was enhanced from 30 Hz to 50 Hz,and the sand body thickness resolution was enhanced from 10 m to 6 m.On the basis of fine layer control by seismic data,three types of seismic facies models,floodplain,natural levee and point bar,were defined,and the intelligent horizon-facies controlled recognition technology was worked out,which had a prediction error of reservoir thickness of less than 1.5 m.Clearly,the description accuracy of meandering channel sand bodies has been improved.The probability semi-quantitative oiliness identification method of fluid by prestack multi-parameters has been worked out by integrating Poisson’s ratio,fluid factor,product of Lame parameter and density,and other prestack elastic parameters,and the method has a coincidence rate of fluid identification of more than 90%,providing solid technical support for the exploration and development of thin reservoirs in Shengli Chengdao extra-shallow sea oilfield,which is expected to provide reference for the exploration and development of similar oilfields in China.
文摘In long-term water drive reservoir, small dose and short radius profile control cannot meet the needs, so deep profile control and flooding are needed. During the placement and processing of conventional deep profile control and flooding agent, the zone classification formed by the changes of pressure field and fluid field are not taken into account. In order to better develop these reservoirs, we proposed a novel deep profile control method, that is, the iso-pressure drop gradient progressive deep profile control method. The key features of the method include: 1) the method took into account the reservoir pressure distribution;2) it proposed a novel standard to divide the orders of zone;3) the method has been successfully applied in 4 wells in China Oilfield. The method divided the formation into near wellbore zone, well-far zone and deep zone according to the drawdown curve. As each zone of the pressure gradient is different and therefore require different intensity of slug. Then design the agent slugs according to iso-pressure drop gradient rule, and the breakthrough pressure gradient of agent is equal to the formation pressure gradient, and it achieved the fluid diversion of whole course by combining the different intensity of blocking agent. The method was applied successfully in 2 wells in China Oilfield from May to November in 2008. The method can smartly improve the sweep efficiency, and field test shows that it can play a very good efficiency of reducing water and increasing oil production. This method is becoming more of a concern in the oilfield develop.
基金The National Natural Science Foundation of China under contract No.41872131。
文摘The geochemical signatures of fifty-four rock samples and three supplementary drill stem test(DST)oils from the Yacheng-Sanya formations in the central Qiongdongnan Basin(CQB)were analysed.Reconstruction of the early Oligocene-early Miocene(36–16 Ma)palaeovegetation and source analyses of organic matter(OM)were conducted using aliphatic biomarkers in ancient sediments and DST oils.Both the interpreted aquatic and terrigenous OM contributed to the CQB source rocks(SRs)but had varying relative proportions.The four distribution patterns derived from n-alkanes,terpanes,and steranes are representative of four OM composition models of the Yacheng-Sanya SRs,including model A,model B,model C,and model D,which were classified based on the increasing contribution from terrigenous OM relative to aquatic OM.Some terrigenous higher plantderived biomarkers,including oleanane,des-A-oleanane,C_(29)ααα20R sterane,bicadinanes,the C_(19)/(C_(19)+C_(23))tricyclic terpane ratio,and other n-alkane-derived ratios suggest that angiosperms had increased proportions in the palaeoflora from early Oligocene to early Miocene,and the bloom of terrigenous higher plants was observed during deposition of upper Lingshui Formation to lower Sanya Formation.These findings are consistent with the incremental total organic carbon and free hydrocarbons+potential hydrocarbons(S_1+S_2)in the lower Lingshuilower Sanya strata with a significant enrichment of OM in the E_3l_1-N_1s_2 shales.The maturity-and environmentsensitive aliphatic parameters of the CQB SRs and DST oils suggest that all the samples have predominantly reached their early oil-generation windows but have not exceeded the peak oil windows,except for some immature Sanya Formation shales.In addition,most of the OM in the analysed samples was characterised by mixed OM contributions under anoxic to sub-anoxic conditions.Furthermore,terrestrial-dominant SRs were interpreted to have developed mainly in the Lingshui-Sanya formations and were deposited in sub-oxic to oxic environments,compared to the anoxic to sub-anoxic conditions of the Yacheng Formation.
基金the National Natural Science Foundation of China(Grant Nos.U1910205 and 41872178)the National Science and Technology Major Project of China(No.2017ZX05064003).
文摘With the deepening of coalbed methane(CBM)exploration and development,the problem of low gas production has gradually become one of the main factors restricting the development of the CBM industry in China.Reasonable well pattern deployment can improve the productivity of CBM wells and reduce the cost of production,while the reservoir changes of CBM wells play a important role for well pattern infilling.In this study,the dynamic characteristics of the average reservoir pressure(ARP),permeability,and drainage radius during the development process of CBM wells are systematically analyzed,and predicted the production changes of well groups before and after infilling wells in combination with the characteristics of reservoir changes.The results show that the high gas production wells have a larger pressure drop,long drainage radius,and a large increase in permeability.On the contrary,low gas production wells are characterized by small drainage radius,damaged permeability and difficult to recover.The productivity of infilled horizontal wells is predicted for two well groups with different productivity and reservoir dynamic characteristics.After infilling wells,the production of current wells has increased at different degrees.It is predicted that the average gas production of low gas production well group H1 and middle gas production well group H2 will increase 1.64 and 2.09 times respectively after 3000 days production simulation.In addition,the pressure interference between wells has increased significantly,and the overall gas production of the well group has greatly increased.Infill wells can achieve better development results in areas with superior CBM resources,recoverable reservoir permeability,and small drainage radius during the early production process.The research results provide a reference for the later infill adjustment of CBM well patterns in the study area.
基金supported by the Fundamental Research Funds for the Central Universities (2652017308)the National Natural Science Foundation of China (Grant Nos. 41372139 and 41072098)the National Science and Technology Major Project of China (2016ZX05046-003-001 and 2016ZX05034-004003)
文摘In this paper, the analysis of faults with different scales and orientations reveals that the distribution of fractures always develops toward a higher degree of similarity with faults, and a method for calculating the multiscale areal fracture density is proposed using fault-fracture self-similarity theory. Based on the fracture parameters observed in cores and thin sections, the initial apertures of multiscale fractures are determined using the constraint method with a skewed distribution. Through calculations and statistical analyses of in situ stresses in combination with physical experiments on rocks, a numerical geomechanical model of the in situ stress field is established. The fracture opening ability under the in situ stress field is subsequently analyzed. Combining the fracture aperture data and areal fracture density at different scales, a calculation model is proposed for the prediction of multiscale and multiperiod fracture parameters, including the fracture porosity, the magnitude and direction of maximum permeability and the flow conductivity. Finally, based on the relationships among fracture aperture,density, and the relative values of fracture porosity and permeability, a fracture development pattern is determined.
基金financial support from the National Natural Science Foundation of China(No.51974282,52074249,51874261)Fundamental Research Funds for the Central Universities(2-9-2019-103)Key Research and Development Program of Shaanxi(No.2021GY-112)。
文摘Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water distribution in rocks during imbibition using various nanofluids was less discussed in previous studies.In this study,we systematically examined the imbibition efficiencies of various nanofluids at60℃.Furthermore,the migration of nanofluids and oil distribution in the rock pores were monitored using nuclear magnetic resonance(NMR).The nanofluids were prepared by dispersing silica nanoparticles and five different types of surfactants i.e.,anionic-nonionic,anionic,nonionic,amphoteric and cationic surfactants in deionized(DI)water.Subsequently,interfacial tension(IFT)and contact angle measurements were conducted to reveal the underlying EOR mechanisms of various nanofluids.The experimental results showed that the EOR potential of the different types of nanofluids was in the order anionic-nonionic>anionic>nonionic>amphoteric>cationic>brine.Anionic-nonionic(sodium lauryl ether sulfate(SLES))and anionic(sodium dodecyl sulfonate(SDS))nanofluids exhibited excellent capability of wettability alteration,and increased oil recovery by 27.96%and 23.08%,respectively,compared to brine.The NMR results also showed that mesopores(0.1-1μm)were the dominant developed pores in the rocks,and contributed the most to imbibition efficiency.In addition,the imbibition of nanofluids initially took place in mesopores and micropores before moving into macropores.This study provides fundamental information on the selection of nanofluids for EOR in tight oil reservoirs.The study also improved the understanding of oil/water distribution during the imbibition of the proposed nanofluids.
