Given that a large amount of crude oil remains on the surface of rocks and is difficult to produce after conventional waterflooding,a new superwetting oil displacement system incorporating the synergy between a hydrox...Given that a large amount of crude oil remains on the surface of rocks and is difficult to produce after conventional waterflooding,a new superwetting oil displacement system incorporating the synergy between a hydroxyl anion compound(1OH-1C)and an extended surfactant(S-C_(13)PO_(13)S)was designed.The interfacial tension,contact angle and emulsification performance of the system were measured.The oil displacement effects and improved oil recovery(IOR)mechanisms of 1OH-1C,S-C_(13)PO_(13)S and their compound system were investigated by microscopic visualization oil displacement experiments and core displacement experiments.The results show that 1OH-1C creates a superwetting interface and electrostatic separation pressure on the solid surface,which destroys the strong interactions between crude oil and quartz to peel off the oil film.S-C_(13)PO_(13)S has low interfacial tension,which can promote the flow of remaining oil and emulsify it into oil-in-water emulsions.The compound system of 1OH-1C and S-C_(13)PO_(13)S has both superwettability and low IFT,which can effectively improve oil recovery through a synergistic effect.The oil displacement experiment of low-permeability natural core shows that the compound solution can increase the oil recovery by 16.4 percentage points after waterflooding.This new high-efficiency system is promising for greatly improving oil recovery in low-permeability reservoirs.展开更多
Nanomaterials and low-salinity water(LSW)are two popular enhanced oil recovery(EOR)methods that have been widely studied in recent years.The former is used for in-depth conformance improvement and the latter for micro...Nanomaterials and low-salinity water(LSW)are two popular enhanced oil recovery(EOR)methods that have been widely studied in recent years.The former is used for in-depth conformance improvement and the latter for microscopic oil displacement(by altering the potential and contact angle).However,there are few literature on combining them to achieve synergistic effects,especially for tight sandstone res-ervoirs.Based on the reservoir conditions of the Jimusar Oilfield,this study investigated the oil recovery mechanism of the combined imbibition system,which was composed of black nanosheet(BN)and LSW.Its performances including decreasing interfacial tension,emulsification,and wettability alterations were evaluated.The imbibition differences between the single system of BN and LSW and the combined BN-LsW imbibition system were then compared.Results showed that the combined imbibition system had a better emulsification effect on the crude oil and could also alter the wettability of the core surface.Moreover,the combined system could increase both the imbibition rate and the ultimate oil recovery.The nuclear magnetic T2 spectrum also indicated that the addition of black nanosheets could divert more fluid into small pores and thus improve the microscopic sweep efficiency.展开更多
The tight-tuff heavy oil reservoir exhibits severe heterogeneity and is characterized by high density,high viscosity,and a high wax content,posing significant challenges for its development.While CO_(2)huffand-puff(H-...The tight-tuff heavy oil reservoir exhibits severe heterogeneity and is characterized by high density,high viscosity,and a high wax content,posing significant challenges for its development.While CO_(2)huffand-puff(H-n-P)enhances oil recovery,these reservoirs struggle with low displacement efficiency.This study proposes a method that combines CO_(2)with an oil-soluble viscosity reducer to improve displacement efficiency in the H-n-P process for tight-tuff heavy oil reservoirs.It also focuses on evaluating pore utilization limits and optimizing the injection strategy.Core samples and crude oil from the TH oilfield(a tight-tuff heavy oil reservoir)were used to conduct online NMR core flooding experiments,including depletion development,water,CO_(2),and HDC(CO_(2)combined with an oil-soluble viscosity reducer)H-n-P injection processes.A single-porosity model accurately reflecting its geological characteristics was developed using the GEM component simulator within the CMG numerical simulation software to investigate the optimized schemes and the enhanced oil recovery potential for a tight-tuff heavy oil reservoir in the TH oilfield.This model was utilized to evaluate the impact of various injection strategies on oilfield recovery efficiency.The study was designed and implemented with five distinct injection schemes.Results showed that oil was produced primarily from large and medium pores during the depletion stage,while water H-n-P,with CO_(2)H-n-P,first targeted macropores,then mesopores,and micropores.The lower pore utilization limit was 0.0267μm.In the HDC H-n-P process,most oil was recovered from water-flooded pores.Still,HDC's lower injection capacity increased the pore utilization limit to 0.03μm,making micropore recovery difficult.Experimental and modeling results suggest that the optimal develo p ment plan for the TH oilfield is one cycle of HDC H-n-P followed by two cycles of CO_(2)H-n-P.This strategy leverages HDC's ability to promote water and oil recovery in the early stage and mass transfer and extraction capacity of CO_(2)in later cycles.Additionally,the characteristics of CO_(2)and HDC H-n-P processes,pore utilization,and recoverable oil(at the pore scale)were evaluated.The results of this study are crucial for refining the reservoir development plan.展开更多
The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is ...The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is a desire to determine whether there is potential for improved oil recovery and to evaluate the economic feasibility. This paper evaluates the benefit of implementing waterflooding, CO2 injection or WAG （water-alternating-gas） recovery methods for improved oil recovery of the Bakken formation. A simulation model resembling the study area was built using CMG-GEM （computer modeling group-generalized equation of state model） reservoir simulation package and a history match of the primary recovery data available was performed. Based on the simulation results, it was concluded that waterflooding had a significant influence on the oil recovery factor, although COz provided the highest increase in crude oil recovery, The capital expenditure for surface facilities and cost of injected fluid was the most economically viable for implementation of waterflooding. The WAG injection simulation results were similar to CO2 injection, except that reservoir pressure was able to be better maintained. Given that high-quality source water is available, waterflooding is the most economically feasible choice according to the simulation results obtained from this study.展开更多
Oil production and mainte nance are essential issues in naturally fractured reservoirs because they are the largest and most productive on earth.However,they present early water and gas channeling but could be remedia...Oil production and mainte nance are essential issues in naturally fractured reservoirs because they are the largest and most productive on earth.However,they present early water and gas channeling but could be remediated by using foaming agents to control these phenomena through blocking channeling areas.In Mexico these reservoirs have pressure up to 5,500 psi,high temperature up to 200℃,salinity up to400,000 ppm,and hardness up to 250,000 ppm;due to these thermodynamic conditions,there has been no available technology to form stable enough foams.In this work,a foaming supramolecular surfactant with the capability to chelate Ca^(2+)ions is examined.As a result,surfactant monomers are bridged by captured Ca^(2+)cations leading to the formation of high-molecular-weight oligomers,which significantly increment the viscosity of the solution improving the foam stability,and since at this manner the Ca2+cations are no longer available to precipitate as components of solid salts,the foaming supramolecular surfactant also performs as antiscalant.These observations are explained through quantum theoretical modeling.The foam is stable,effectively blocking the gas channels,whereas in presence of oil the foam is broken leading the oil to pass into the wellbore.The characteristic rheological properties of the foam allow its injection into the formation at a range of flow rates,foam qualities,and shear stress to achieve the flooding and the blocking of a variety of fractured carbonate formations,and the change of the wettability of the matrix,which is a desirable behavior in a huff and puff process,as reported in a previous publication about a successful pilot test of this foam.展开更多
Geo-energy and geo-engineering applications,such as improved oil recovery(IOR),geologic carbon storage,and enhanced geothermal systems(EGSs),involve coupled thermo-hydro-mechanical(THM)processes that result from fluid...Geo-energy and geo-engineering applications,such as improved oil recovery(IOR),geologic carbon storage,and enhanced geothermal systems(EGSs),involve coupled thermo-hydro-mechanical(THM)processes that result from fluid injection and production.In some cases,reservoirs are highly fractured and the geomechanical response is controlled by fractures.Therefore,fractures should explicitly be included into numerical models to realistically simulate the THM responses of the subsurface.In this study,we perform coupled THM numerical simulations of water injection into naturally fractured reservoirs(NFRs)using CODE_BRIGHT and TOUGH-UDEC codes.CODE_BRIGHT is a finite element method(FEM)code that performs fully coupled THM analysis in geological media and TOUGH-UDEC sequentially solves coupled THM processes by combining a finite volume method(FVM)code that solves nonisothermal multiphase flow(TOUGH2)with a distinct element method(DEM)code that solves the mechanical problem(UDEC).First,we validate the two codes against a semi-analytical solution for water injection into a single deformable fracture considering variable permeability based on the cubic law.Then,we compare simulation results of the two codes in an idealized conceptual model that includes one horizontal fracture and in a more realistic model with multiple fractures.Each code models fractures differently.UDEC calculates fracture deformation from the fracture normal and shear stiffnesses,while CODE_BRIGHT treats fractures as equivalent porous media and uses the equivalent Young’s modulus and Poisson’s ratio of the fracture.Finally,we obtain comparable results of pressure,temperature,stress and displacement distributions and evolutions for the single horizontal fracture model.Despite some similarities,the two codes provide increasingly different results as model complexity increases.These differences highlight the challenging task of accurately modeling coupled THM processes in fractured media given their high nonlinearity.展开更多
Water flooding and pressure maintenance are recommended to improve oil recovery practices after low recovery of petroleum reservoirs occurs during primary production.Salt crystal formation is a frequent occurrence whe...Water flooding and pressure maintenance are recommended to improve oil recovery practices after low recovery of petroleum reservoirs occurs during primary production.Salt crystal formation is a frequent occurrence when using these techniques.Several experimental,numerical,and theoretical studies have been done on the mechanisms underlying scaling and permeability reduction in porous media;however,there has not been a satisfactory model developed.This study developed a phenomenological model to predict formation damage caused by salt deposition.Compared with existing models,which provide a scaling tendency,the proposed model predicts the profile of scale deposition.The salt precipitation model simulates reactive fluid flow through porous media.A thermodynamic,kinetic,and flow hydrodynamic model was developed and coupled with the ion transport equation to describe the movement of ions.Further,a set of carefully designed dynamic experiments were conducted and the data were compared with the model predictions.Model forecasts and experimental data were observed to have an average absolute error(AAE)ranging from 0.68%to 5.94%,which indicates the model's suitability.展开更多
基金Supported by the National Key R&D Program of China(2019YFA0708700,2023YFF0614100)CNPC Major Science and Technology Project(2021ZZ01,2023ZZ04).
文摘Given that a large amount of crude oil remains on the surface of rocks and is difficult to produce after conventional waterflooding,a new superwetting oil displacement system incorporating the synergy between a hydroxyl anion compound(1OH-1C)and an extended surfactant(S-C_(13)PO_(13)S)was designed.The interfacial tension,contact angle and emulsification performance of the system were measured.The oil displacement effects and improved oil recovery(IOR)mechanisms of 1OH-1C,S-C_(13)PO_(13)S and their compound system were investigated by microscopic visualization oil displacement experiments and core displacement experiments.The results show that 1OH-1C creates a superwetting interface and electrostatic separation pressure on the solid surface,which destroys the strong interactions between crude oil and quartz to peel off the oil film.S-C_(13)PO_(13)S has low interfacial tension,which can promote the flow of remaining oil and emulsify it into oil-in-water emulsions.The compound system of 1OH-1C and S-C_(13)PO_(13)S has both superwettability and low IFT,which can effectively improve oil recovery through a synergistic effect.The oil displacement experiment of low-permeability natural core shows that the compound solution can increase the oil recovery by 16.4 percentage points after waterflooding.This new high-efficiency system is promising for greatly improving oil recovery in low-permeability reservoirs.
基金funded by the Karamay Innovative Environment Construction Plan(Innovative Talents)Project(No.20212022hjcxrc0015)the Research Foundation of China University of Petroleum-Beijing at Karamay(No.XQZX20200010)+3 种基金the University Scientific Research Project of Xinjiang Uygur Autonomous Region(No.XJEDU2019Y067)the Natural Science Foundation of Xinjiang Uygur Autonomous Region(No.2019D01B57)the CNPC Strategic Cooperation Science and Technology Project(No.ZLZX2020-01-04-04)the Sichuan Province Regional Innovation Cooperation Project(No.2020YFQ0036).
文摘Nanomaterials and low-salinity water(LSW)are two popular enhanced oil recovery(EOR)methods that have been widely studied in recent years.The former is used for in-depth conformance improvement and the latter for microscopic oil displacement(by altering the potential and contact angle).However,there are few literature on combining them to achieve synergistic effects,especially for tight sandstone res-ervoirs.Based on the reservoir conditions of the Jimusar Oilfield,this study investigated the oil recovery mechanism of the combined imbibition system,which was composed of black nanosheet(BN)and LSW.Its performances including decreasing interfacial tension,emulsification,and wettability alterations were evaluated.The imbibition differences between the single system of BN and LSW and the combined BN-LsW imbibition system were then compared.Results showed that the combined imbibition system had a better emulsification effect on the crude oil and could also alter the wettability of the core surface.Moreover,the combined system could increase both the imbibition rate and the ultimate oil recovery.The nuclear magnetic T2 spectrum also indicated that the addition of black nanosheets could divert more fluid into small pores and thus improve the microscopic sweep efficiency.
基金funded by the Natural Science Foundation of Beijing Municipality(3232028)the National Natural Science Foundation of China(52274053)the National Foreign Expert Individual Project(H20240045)。
文摘The tight-tuff heavy oil reservoir exhibits severe heterogeneity and is characterized by high density,high viscosity,and a high wax content,posing significant challenges for its development.While CO_(2)huffand-puff(H-n-P)enhances oil recovery,these reservoirs struggle with low displacement efficiency.This study proposes a method that combines CO_(2)with an oil-soluble viscosity reducer to improve displacement efficiency in the H-n-P process for tight-tuff heavy oil reservoirs.It also focuses on evaluating pore utilization limits and optimizing the injection strategy.Core samples and crude oil from the TH oilfield(a tight-tuff heavy oil reservoir)were used to conduct online NMR core flooding experiments,including depletion development,water,CO_(2),and HDC(CO_(2)combined with an oil-soluble viscosity reducer)H-n-P injection processes.A single-porosity model accurately reflecting its geological characteristics was developed using the GEM component simulator within the CMG numerical simulation software to investigate the optimized schemes and the enhanced oil recovery potential for a tight-tuff heavy oil reservoir in the TH oilfield.This model was utilized to evaluate the impact of various injection strategies on oilfield recovery efficiency.The study was designed and implemented with five distinct injection schemes.Results showed that oil was produced primarily from large and medium pores during the depletion stage,while water H-n-P,with CO_(2)H-n-P,first targeted macropores,then mesopores,and micropores.The lower pore utilization limit was 0.0267μm.In the HDC H-n-P process,most oil was recovered from water-flooded pores.Still,HDC's lower injection capacity increased the pore utilization limit to 0.03μm,making micropore recovery difficult.Experimental and modeling results suggest that the optimal develo p ment plan for the TH oilfield is one cycle of HDC H-n-P followed by two cycles of CO_(2)H-n-P.This strategy leverages HDC's ability to promote water and oil recovery in the early stage and mass transfer and extraction capacity of CO_(2)in later cycles.Additionally,the characteristics of CO_(2)and HDC H-n-P processes,pore utilization,and recoverable oil(at the pore scale)were evaluated.The results of this study are crucial for refining the reservoir development plan.
文摘The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is a desire to determine whether there is potential for improved oil recovery and to evaluate the economic feasibility. This paper evaluates the benefit of implementing waterflooding, CO2 injection or WAG （water-alternating-gas） recovery methods for improved oil recovery of the Bakken formation. A simulation model resembling the study area was built using CMG-GEM （computer modeling group-generalized equation of state model） reservoir simulation package and a history match of the primary recovery data available was performed. Based on the simulation results, it was concluded that waterflooding had a significant influence on the oil recovery factor, although COz provided the highest increase in crude oil recovery, The capital expenditure for surface facilities and cost of injected fluid was the most economically viable for implementation of waterflooding. The WAG injection simulation results were similar to CO2 injection, except that reservoir pressure was able to be better maintained. Given that high-quality source water is available, waterflooding is the most economically feasible choice according to the simulation results obtained from this study.
基金supports granted by Instituto Mexicano del Petr oleo (IMP) through the Project Y.00123 “Procesos de RM en yacimientos carbonatados fracturados de alta salinidad y temperatura con base en el dise~no, desarrollo y escalamiento de productos químicos ad hoc”financially supported by the SENER-CONACYT/Hidrocarburos fund through the Project 146735, D.61029 “Dise~no y síntesis de nuevos prototipos de productos químicos multifuncionales con propiedades dispersantes de asfaltenos modificadoras de la mojabilidad y desemulsificantes”
文摘Oil production and mainte nance are essential issues in naturally fractured reservoirs because they are the largest and most productive on earth.However,they present early water and gas channeling but could be remediated by using foaming agents to control these phenomena through blocking channeling areas.In Mexico these reservoirs have pressure up to 5,500 psi,high temperature up to 200℃,salinity up to400,000 ppm,and hardness up to 250,000 ppm;due to these thermodynamic conditions,there has been no available technology to form stable enough foams.In this work,a foaming supramolecular surfactant with the capability to chelate Ca^(2+)ions is examined.As a result,surfactant monomers are bridged by captured Ca^(2+)cations leading to the formation of high-molecular-weight oligomers,which significantly increment the viscosity of the solution improving the foam stability,and since at this manner the Ca2+cations are no longer available to precipitate as components of solid salts,the foaming supramolecular surfactant also performs as antiscalant.These observations are explained through quantum theoretical modeling.The foam is stable,effectively blocking the gas channels,whereas in presence of oil the foam is broken leading the oil to pass into the wellbore.The characteristic rheological properties of the foam allow its injection into the formation at a range of flow rates,foam qualities,and shear stress to achieve the flooding and the blocking of a variety of fractured carbonate formations,and the change of the wettability of the matrix,which is a desirable behavior in a huff and puff process,as reported in a previous publication about a successful pilot test of this foam.
基金financial support received from the“Iran’s Ministry of Science Research and Technology”(PhD students’sabbatical grants)funding from the European Research Council under the European Union’s Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST(www.georest.eu)(Grant Agreement No.801809)+1 种基金support by the Korea-EU Joint Research Program of the National Research Foundation of Korea through Grant No.NRF2015K1A3A7A03074226funded by the Korean Government’s Ministry of Science and Information and Communication Technology(ICT)in the framework of the European Union’s Horizon 2020 Research and Innovation Program(Grant No.691728)。
文摘Geo-energy and geo-engineering applications,such as improved oil recovery(IOR),geologic carbon storage,and enhanced geothermal systems(EGSs),involve coupled thermo-hydro-mechanical(THM)processes that result from fluid injection and production.In some cases,reservoirs are highly fractured and the geomechanical response is controlled by fractures.Therefore,fractures should explicitly be included into numerical models to realistically simulate the THM responses of the subsurface.In this study,we perform coupled THM numerical simulations of water injection into naturally fractured reservoirs(NFRs)using CODE_BRIGHT and TOUGH-UDEC codes.CODE_BRIGHT is a finite element method(FEM)code that performs fully coupled THM analysis in geological media and TOUGH-UDEC sequentially solves coupled THM processes by combining a finite volume method(FVM)code that solves nonisothermal multiphase flow(TOUGH2)with a distinct element method(DEM)code that solves the mechanical problem(UDEC).First,we validate the two codes against a semi-analytical solution for water injection into a single deformable fracture considering variable permeability based on the cubic law.Then,we compare simulation results of the two codes in an idealized conceptual model that includes one horizontal fracture and in a more realistic model with multiple fractures.Each code models fractures differently.UDEC calculates fracture deformation from the fracture normal and shear stiffnesses,while CODE_BRIGHT treats fractures as equivalent porous media and uses the equivalent Young’s modulus and Poisson’s ratio of the fracture.Finally,we obtain comparable results of pressure,temperature,stress and displacement distributions and evolutions for the single horizontal fracture model.Despite some similarities,the two codes provide increasingly different results as model complexity increases.These differences highlight the challenging task of accurately modeling coupled THM processes in fractured media given their high nonlinearity.
文摘Water flooding and pressure maintenance are recommended to improve oil recovery practices after low recovery of petroleum reservoirs occurs during primary production.Salt crystal formation is a frequent occurrence when using these techniques.Several experimental,numerical,and theoretical studies have been done on the mechanisms underlying scaling and permeability reduction in porous media;however,there has not been a satisfactory model developed.This study developed a phenomenological model to predict formation damage caused by salt deposition.Compared with existing models,which provide a scaling tendency,the proposed model predicts the profile of scale deposition.The salt precipitation model simulates reactive fluid flow through porous media.A thermodynamic,kinetic,and flow hydrodynamic model was developed and coupled with the ion transport equation to describe the movement of ions.Further,a set of carefully designed dynamic experiments were conducted and the data were compared with the model predictions.Model forecasts and experimental data were observed to have an average absolute error(AAE)ranging from 0.68%to 5.94%,which indicates the model's suitability.
