Two actual rocks drilled from a typical ultra-deep hydrocarbon reservoir in the Tarim Basin are selected to conduct in-situ stress-loading micro-focus CT scanning experiments.The gray images of rock microstructure at ...Two actual rocks drilled from a typical ultra-deep hydrocarbon reservoir in the Tarim Basin are selected to conduct in-situ stress-loading micro-focus CT scanning experiments.The gray images of rock microstructure at different stress loading stages are obtained.The U-Net fully convolutional neural network is utilized to achieve fine semantic segmentation of rock skeleton,pore space,and microfractures based on CT slice images of deep rocks.The three-dimensional digital rock models of deformed multiscale fractured-porous media at different stress loading stages are thereafter reconstructed,and the equivalent fracture-pore network models are finally extracted to explore the underlying mechanisms of gas-water two-phase flow at the pore-scale.Results indicate that,in the process of insitu stress loading,both the deep rocks have experienced three stages:linear elastic deformation,nonlinear plastic deformation,and shear failure.The micro-mechanical behavior greatly affects the dynamic deformation of rock microstructure and gas-water two-phase flow.In the linear elastic deformation stage,with the increase in in-situ stress,both the deep rocks are gradually compacted,leading to decreases in average pore radius,pore throat ratio,tortuosity,and water-phase relative permeability,while the coordination number nearly remains unchanged.In the plastic deformation stage,the synergistic influence of rock compaction and existence of micro-fractures typically exert a great effect on pore-throat topological properties and gas-water relative permeability.In the shear failure stage,due to the generation and propagation of micro-fractures inside the deep rock,the topological connectivity becomes better,fluid flow paths increase,and flow conductivity is promoted,thus leading to sharp increases in average pore radius and coordination number,rapid decreases in pore throat ratio and tortuosity,as well as remarkable improvement in relative permeability of gas phase and waterphase.展开更多
In-depth profile control is a crucial technique employed to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,it is a challenge to achieve in-depth profile control.In this paper,two types of organic...In-depth profile control is a crucial technique employed to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,it is a challenge to achieve in-depth profile control.In this paper,two types of organic gel systems,namely s-MPG and MSRG,tailored for fractured-vuggy reservoirs with 140℃ and 22×10^(4) mg/L have been developed.FTIR was used to analyze the functional groups of s-MPG and MSRG.Additionally,the quality retention rates of s-MPG and MSRG were assessed using TG-DSC,yielding results of 92.85%and 92.65%,respectively.The dilution rates of s-MPG and MSRG are found to be 18.69%and 26.69%,respectively,demonstrating excellent compatibility and adaptability.The enhancement performance depends on the synergistic effect that the anti-dilution s-MPG effectively separates bottom water,while high-strength MSRG separates the oil layer.Moreover,the EOR perfor-mances of s-MPG synergy with MSRG in various types of fractured-vuggy carbonate models were also evaluated.The highest oil recovery of 12%is achieved in fracture network model.Laboratory results indicate that the synergistic combination of s-MPG and MSRG for water plugging in fractured-vuggy carbonate reservoirs results in a more effective enhancement of oil recovery compared to using a sin-gle gel system for plugging.Finally,the s-MPG synergy with MSRG has been applied in actual fractured-vuggy carbonate reservoirs.As expected,the water cut of typical well is reduced from 100%to 30%and the increased oil production is 1142 t totally.Therefore,this study presents a novel approach to achieving in-depth profile control by leveraging the synergistic effect of s-MPG with MSRG in fractured-vuggy carbonate reservoirs.展开更多
Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant...Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate(APGSHS) and zwitterionic surfactant octadecyl betaine(BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile,the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt%while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.展开更多
Inadequate strength and stability of active crude oil emulsions stabilized by conventional surfactants always lead to a limited plugging rate of plugging agents.Thus,to address this issue,the synthesis of amphiphilic ...Inadequate strength and stability of active crude oil emulsions stabilized by conventional surfactants always lead to a limited plugging rate of plugging agents.Thus,to address this issue,the synthesis of amphiphilic Janus nanosheets was effectively carried out for enhancing the system performances and subsequently characterized.Based on the outcomes of orthogonal tests,an assessment was conducted on the nanosheet and surfactant formulations to optimize the enhancement of emulsion properties.The experimental demonstration of the complex system has revealed its remarkable emulsifying capability,ability to decrease interfacial tension and improve rheological behavior at high temperature(80℃)and high salinity(35,000 ppm)conditions.Involving probable mechanism of the system performance enhancement is elucidated by considering the synergistic effect between surfactants and nanosheets.Furthermore,variables including water-to-oil ratio,salinity,temperature and stirring intensity during operation,which affect the properties of prepared emulsions,were investigated in detail.The efficacy and stability of the complex system in obstructing medium and high permeability cores were demonstrated.Notably,the core with a high permeability of 913.58 mD exhibited a plugging rate of 98.55%.This study establishes the foundations of medium and high permeability reservoirs plugging with novel active crude oil plugging agents in severe environments.展开更多
Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and hi...Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs.Consequently,a novel conformance control system HPF-Co gel,based on high-temperature stabilizer(CoCl_(2)·H_(2)O,CCH)is developed.The HPF-Co bulk gel has better performances with high temperature(120℃)and high salinity(1×10^(5)mg/L).According to Sydansk coding system,the gel strength of HPF-Co with CCH is increased to code G.The dehydration rate of HPF-Co gel is 32.0%after aging for 150 d at 120℃,showing excellent thermal stability.The rheological properties of HPF gel and HPF-Co gel are also studied.The results show that the storage modulus(G′)of HPF-Co gel is always greater than that of HPF gel.The effect of CCH on the microstructure of the gel is studied.The results show that the HPF-Co gel with CCH has a denser gel network,and the diameter of the three-dimensional network skeleton is 1.5-3.5μm.After 90 d of aging,HPF-Co gel still has a good three-dimensional structure.Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group,which can suppress the vibration of cross-linked sites and improve the stability at high temperature.Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system,plugging rate exceeding 98%.Moreover,the results of subsequent waterflooding recovery can be improved by 17%.展开更多
Despite advances in renewable energy sources, the world's current infrastructure and consumption patterns still heavily depend on crude oil. Enhanced oil recovery(EOR) is a crucial method for significantly increas...Despite advances in renewable energy sources, the world's current infrastructure and consumption patterns still heavily depend on crude oil. Enhanced oil recovery(EOR) is a crucial method for significantly increasing the amount of crude oil extracted from mature and declining oil fields. Nanomaterials have shown great potential in improving EOR methods due to their unique properties, such as high surface area, tunable surface chemistry, and the ability to interact at the molecular level with fluids and rock surfaces. This study examines the potential use of incorporating ethoxylated molybdenum disulfide with a unique three-dimensional flower-like morphology for overcoming the challenges associated with oil recovery from reservoirs characterized by complex pore structures and low permeability. The synthesized nanomaterial features a chemical composition that encompasses a polar ethoxy group linking molybdenum disulfide nanosheets and an alkylamine chain. The ethoxy group promotes interactions with water molecules through hydrogen bonding and electrostatic forces, disrupting the cohesive forces among water molecules and reduction surface tension at the oil-water interface. As a result, the nanomaterial achieves an ultra-low interfacial tension of 10^(-3) mN/m. Core flooding experiments demonstrate a significant oil recovery of approximately 70% at a concentration as low as 50 ppm. This research paves the way for the design and synthesis of advanced extended surfactant-like nanomaterials,offering a promising avenue for enhancing oil recovery efficiency.展开更多
A novel concept of treating oil reservoirs by nanofluids is being developed to improve oil recovery and reduce the trapped oil in hydrocarbon reservoirs.Nanoparticles show great potential in enhancing oil recovery und...A novel concept of treating oil reservoirs by nanofluids is being developed to improve oil recovery and reduce the trapped oil in hydrocarbon reservoirs.Nanoparticles show great potential in enhancing oil recovery under ambient conditions.In this paper,the approaches of wettability alteration by using nanofluid,stability of nanofluids,and the most reliable wettability alteration mechanisms associated with variant types of nanoparticles have been reviewed.Moreover,the parameters that have a significant influence on nanofluid flooding have been discussed.Finally,the recent studies of the effect of nanoparticles on wettability alteration have been summarised and analysed.Furthermore,this paper presents possible opportunities and challenges regarding wettability alteration using nanofluids.展开更多
Nanofluid offers more opportunities and challenges over the traditional surfactant and polymer solutions during enhanced oil recovery(commonly referred to as tertiary oil recovery)due to its remarkable properties.This...Nanofluid offers more opportunities and challenges over the traditional surfactant and polymer solutions during enhanced oil recovery(commonly referred to as tertiary oil recovery)due to its remarkable properties.This review mainly discusses the preparation methods of amphiphilic nanoparticles due to their higher interface activity than sole hydrophilic or hydrophobic nanoparticles(SHNPs).The nanofluids’stability is reviewed in this work.Moreover,the mechanisms of nanofluids in enhancing oil recovery(N-EOR)in terms of interfacial tension reduction,wettability alteration,foam stabilization,emulsion stabilization,structural disjoining pressure,and depressurization-increasing injection are mainly summarized and reviewed.Also,the synergistic effects of nanofluids and traditional surfactants and polymers are discussed.Finally,nanofluids’challenges and prospects are also outlined.The nanofluids can still be regarded as an outstanding candidate for enhancing oil recovery significantly in the future although there are limitations on their applications from laboratory scale to field scale.展开更多
With complex fractured-vuggy heterogeneous structures, water has to be injected to facilitate oil pro- duction. However, the effect of different water injection modes on oil recovery varies. The limitation of existing...With complex fractured-vuggy heterogeneous structures, water has to be injected to facilitate oil pro- duction. However, the effect of different water injection modes on oil recovery varies. The limitation of existing numerical simulation methods in representing fractured- vuggy carbonate reservoirs makes numerical simulation difficult to characterize the fluid flow in these reservoirs. In this paper, based on a geological example unit in the Tahe Oilfield, a three-dimensional physical model was designed and constructed to simulate fluid flow in a fractured-vuggy reservoir according to similarity criteria. The model was validated by simulating a bottom water drive reservoir, and then subsequent water injection modes were optimized. These were continuous （constant rate）, intermittent, and pulsed injection of water. Experimental results reveal that due to the unbalanced formation pressure caused by pulsed water injection, the swept volume was expanded and consequently the highest oil recovery increment was achieved. Similar to continuous water injection, intermit- tent injection was influenced by factors including the connectivity of the fractured-vuggy reservoir, well depth, and the injection-production relationship, which led to a relative low oil recovery. This study may provide a constructive guide to field production and for the devel- opment of the commercial numerical models specialized for fractured-vuggy carbonate reservoirs.展开更多
Gas injection serves as a main enhanced oil recovery(EOR)method in fractured-vuggy carbonate reservoir,but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configurati...Gas injection serves as a main enhanced oil recovery(EOR)method in fractured-vuggy carbonate reservoir,but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configuration.Many researchers conducted experiments for the observation of fluid flow and the evaluation of production performance,while most of their physical models were fabricated based on the probability distribution of fractures and caves in the reservoir.In this study,a two-dimensional physical model of the karst fault system was designed and fabricated based on the geological model of TK748 well group in the seventh block of the Tahe Oilfield.The fluid flow and production performance of primary gas flooding were discussed.Gas-assisted gravity flooding was firstly introduced to take full use of gas-oil gravity difference,and its feasibility in the karst fault system was examined.Experimental results showed that primary gas flooding created more flow paths and achieved a remarkable increment of oil recovery compared to water flooding.Gas injection at a lower location was recommended to delay gas breakthrough.Gas-assisted gravity flooding achieved more stable gas-displacing-oil because oil production was at a lower location,and thus,the oil recovery was further enhanced.展开更多
The development of fractured-vuggy carbonate reservoirs is extremely difficult because of the complex fractured-vuggy structure and strong heterogeneity.Foam flooding is a potential enhanced oil recovery(EOR)technolog...The development of fractured-vuggy carbonate reservoirs is extremely difficult because of the complex fractured-vuggy structure and strong heterogeneity.Foam flooding is a potential enhanced oil recovery(EOR)technology in fractured-vuggy carbonate reservoirs.Based on the similarity criterion,three types of 2D visual physical models of the fractured-vuggy structure were made by laser ablation technique,and a 3D visual physical model of the fractured-vuggy reservoir was made by 3D printing technology.Then the physical analog experiments of foam flooding were carried out in these models.The experimental results show that foam can effectively improve the mobility ratio,control the flow velocity of the fluid in different directions,and sweep complex fracture networks.The effect of foam flooding in fractures can be improved by increasing foam strength and enhancing foam stability.The effect of foam flooding in vugs can be improved by reducing the density of the foam and the interfacial tension between foam and oil.Three types of microscopic residual oil and three types of macroscopic residual oil can be displaced by foam flooding.This study verifies the EOR of foam flooding in the fractured-vuggy reservoir and provides theoretical support for the application of foam flooding in fractured-vuggy 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
Nanoparticles have been widely used in polymer gel systems in recent years to improve gelation performance under high-temperature reservoir conditions. However, different types of nanoparticles have different effects ...Nanoparticles have been widely used in polymer gel systems in recent years to improve gelation performance under high-temperature reservoir conditions. However, different types of nanoparticles have different effects on their gelation performance, which has been little researched. In this study, the high-temperature gelation performance, chemical structure, and microstructure of polymer gels prepared from two nanomaterials (i.e., nano-SiO_(2) and nano-TiO_(2)) were measured. The conventional HPAM/PEI polymer gel system was employed as the control sample. Results showed that the addition of nano-TiO_(2) could significantly enhance the gel strength of HPAM/PEI gel at 80 ℃. The gel strength of the enhanced HPAM/PEI gel with 0.1 wt% nano-TiO_(2) could reach grade I. The system also had excellent high-temperature stability at 150 ℃. The enhanced HPAM/PEI gel with 0.02 wt% nano-TiO_(2) reached the maximum gel strength at 150 ℃ with a storage modulus (G′) of 15 Pa, which can meet the need for efficient plugging. However, the nano-SiO_(2) enhanced HPAM/PEI polymer gel system showed weaker gel strength than that with nano-TiO_(2) at both 80 and 150 ℃ with G′ lower than 5 Pa. Microstructures showed that the nano-TiO_(2) enhanced HPAM/PEI gel had denser three-dimensional (3D) mesh structures, which makes the nano-TiO_(2) enhanced HPAM/PEI gel more firmly bound to water. The FT-IR results also confirmed that the chemical structure of the nano-TiO_(2) enhanced HPAM/PEI gel was more thermally stable than nano-SiO_(2) since there was a large amount of –OH groups on the structure surface. Therefore, nano-TiO_(2) was more suitable as the reinforcing material for HPAM/PEI gels for high-temperature petroleum reservoir conformance improvement.展开更多
Plugging agents have been widely used to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,the harsh conditions of fractured-vuggy carbonate reservoirs yield a significant challenge in maintaining a...Plugging agents have been widely used to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,the harsh conditions of fractured-vuggy carbonate reservoirs yield a significant challenge in maintaining a long-term stabilization of plugging agents.In this work,we developed an anti-hightemperature and high-salinity polymer gel(APG)with excellent resistance to high temperature(140℃)and ultra-high salinity(240000 mg/L).The rheology and microstructure of APG were characterized before and after gelation.Core plugging tests on fractured cubic cores were conducted to quantify the plugging performance of the gel system.Experimental results showed that the Sclerglucan and Cobalt(Ⅱ)Chloride Hexahydrate filled the three-dimensional(3-D)network with various morphologies,providing extra protection to the cross-linking points of the 3D network structure of APG and thus,leading to a prolongation of the dehydration time.The dehydration rate of APG was only 5%within 30days,and the strength of APG could be maintained at a rigid or near-rigid level over 150 days.Moreover,APG exhibited satisfactory shear and scour resistance.Core plugging tests showed that APG could achieve a plugging rate of 90%and demonstrate ignorable minor damage to the substrate.Our results indicate that APG can serve as a great candidate in channel plugging in fractured-vuggy carbonate reservoirs where fractures are fully developed.展开更多
Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight ...Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs,owing to its advantages in reducing oil viscosity,improving mobility ratio,quickly replenishing formation pressure,and potentially achieving a miscible state.However,reliable inhouse laboratory evaluation of CO_(2) huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure.In this study,we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO_(2) injection in a tight conglomerate reservoir.The impacts of depletion degree,pore volume injection of CO_(2) and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure.Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency(first increased and then decreased)with increased CO_(2) injection volume and soaking time.The lower oil recoveries under excess CO_(2) injection and soaking time were attributed to limited CO_(2) dissolution and asphaltene precipitation.This work guides secure and reliable laboratory design of CO_(2) huff-n-puff in tight reservoirs with high formation pressure.展开更多
Fine particle detachment and subsequent migration can lead to severe pore plugging and consequent permeability decline.Therefore,it is crucial to quantify the critical condition when fine particle detachment occurs.Th...Fine particle detachment and subsequent migration can lead to severe pore plugging and consequent permeability decline.Therefore,it is crucial to quantify the critical condition when fine particle detachment occurs.The frequently observed deviations or even contradictions between experimental results and theoretical predictions of fines detachment arise from an insufficient understanding of adhesion force that can be highly influenced by salinity and temperature.To clarify the intrinsic influence of salinity and temperature on fines detachment,adhesion forces between carboxyl microspheres and hydrophilic silica substrates in an aqueous medium were measured at various salinities and tempera-tures using atomic force microscopy(AFM).The AFM-measured adhesion force decreases with increasing salinity or temperature.Trends of mean measured adhesion forces with temperature and salinity were compared with the DLVO and XDLVO theories.DLVO theory captured the trend with temperature via the impact of temperature on electric double layer interactions,whereas XDLVO theory captured the observed trend with salinity via the impact of salinity on the repulsive hydration force.Our results highlight the significance of hydration force in accurately predicting the fate of fines in porous media.展开更多
基金supported by the National Natural Science Foundation of China(No.52174043)the Beijing Natural Science Foundation(No.3242019)+1 种基金the CNPC Innovation Foundation(No.2022DQ02-0208)the State Key Laboratory of Deep Oil and Gas(No.SKLD0G2024-KFZD-06).
文摘Two actual rocks drilled from a typical ultra-deep hydrocarbon reservoir in the Tarim Basin are selected to conduct in-situ stress-loading micro-focus CT scanning experiments.The gray images of rock microstructure at different stress loading stages are obtained.The U-Net fully convolutional neural network is utilized to achieve fine semantic segmentation of rock skeleton,pore space,and microfractures based on CT slice images of deep rocks.The three-dimensional digital rock models of deformed multiscale fractured-porous media at different stress loading stages are thereafter reconstructed,and the equivalent fracture-pore network models are finally extracted to explore the underlying mechanisms of gas-water two-phase flow at the pore-scale.Results indicate that,in the process of insitu stress loading,both the deep rocks have experienced three stages:linear elastic deformation,nonlinear plastic deformation,and shear failure.The micro-mechanical behavior greatly affects the dynamic deformation of rock microstructure and gas-water two-phase flow.In the linear elastic deformation stage,with the increase in in-situ stress,both the deep rocks are gradually compacted,leading to decreases in average pore radius,pore throat ratio,tortuosity,and water-phase relative permeability,while the coordination number nearly remains unchanged.In the plastic deformation stage,the synergistic influence of rock compaction and existence of micro-fractures typically exert a great effect on pore-throat topological properties and gas-water relative permeability.In the shear failure stage,due to the generation and propagation of micro-fractures inside the deep rock,the topological connectivity becomes better,fluid flow paths increase,and flow conductivity is promoted,thus leading to sharp increases in average pore radius and coordination number,rapid decreases in pore throat ratio and tortuosity,as well as remarkable improvement in relative permeability of gas phase and waterphase.
基金support of Sinopec Northwest Oilfield Company,Xinjiang Urumqi(Grant No.KJ202336).
文摘In-depth profile control is a crucial technique employed to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,it is a challenge to achieve in-depth profile control.In this paper,two types of organic gel systems,namely s-MPG and MSRG,tailored for fractured-vuggy reservoirs with 140℃ and 22×10^(4) mg/L have been developed.FTIR was used to analyze the functional groups of s-MPG and MSRG.Additionally,the quality retention rates of s-MPG and MSRG were assessed using TG-DSC,yielding results of 92.85%and 92.65%,respectively.The dilution rates of s-MPG and MSRG are found to be 18.69%and 26.69%,respectively,demonstrating excellent compatibility and adaptability.The enhancement performance depends on the synergistic effect that the anti-dilution s-MPG effectively separates bottom water,while high-strength MSRG separates the oil layer.Moreover,the EOR perfor-mances of s-MPG synergy with MSRG in various types of fractured-vuggy carbonate models were also evaluated.The highest oil recovery of 12%is achieved in fracture network model.Laboratory results indicate that the synergistic combination of s-MPG and MSRG for water plugging in fractured-vuggy carbonate reservoirs results in a more effective enhancement of oil recovery compared to using a sin-gle gel system for plugging.Finally,the s-MPG synergy with MSRG has been applied in actual fractured-vuggy carbonate reservoirs.As expected,the water cut of typical well is reduced from 100%to 30%and the increased oil production is 1142 t totally.Therefore,this study presents a novel approach to achieving in-depth profile control by leveraging the synergistic effect of s-MPG with MSRG in fractured-vuggy carbonate reservoirs.
基金financially supported by National Natural Science Foundation of China(No.22302229)Beijing Municipal Excellent Talent Training Funds Youth Advanced Individual Project(No.2018000020124G163)。
文摘Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate(APGSHS) and zwitterionic surfactant octadecyl betaine(BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile,the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt%while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.
基金financially supported by National Natural Science Foundation of China(52374053)Beijing Natural Science Foundation(2204092)Beijing Municipal Excellent Talent Training Funds Youth Advanced Individual Project(2018000020124G163)。
文摘Inadequate strength and stability of active crude oil emulsions stabilized by conventional surfactants always lead to a limited plugging rate of plugging agents.Thus,to address this issue,the synthesis of amphiphilic Janus nanosheets was effectively carried out for enhancing the system performances and subsequently characterized.Based on the outcomes of orthogonal tests,an assessment was conducted on the nanosheet and surfactant formulations to optimize the enhancement of emulsion properties.The experimental demonstration of the complex system has revealed its remarkable emulsifying capability,ability to decrease interfacial tension and improve rheological behavior at high temperature(80℃)and high salinity(35,000 ppm)conditions.Involving probable mechanism of the system performance enhancement is elucidated by considering the synergistic effect between surfactants and nanosheets.Furthermore,variables including water-to-oil ratio,salinity,temperature and stirring intensity during operation,which affect the properties of prepared emulsions,were investigated in detail.The efficacy and stability of the complex system in obstructing medium and high permeability cores were demonstrated.Notably,the core with a high permeability of 913.58 mD exhibited a plugging rate of 98.55%.This study establishes the foundations of medium and high permeability reservoirs plugging with novel active crude oil plugging agents in severe environments.
基金This work has been Sponsored by CNPC Innovation Found(Grant No.2021DQ02-0202)Besides,the authors gratefully appreciate the financial support of the Science Foundation of China University of Petroleum,Beijing(Grant No.2462020XKBH013)Financial supports from the National Natural Science Foundation of China(Grant No.52174046)is also significantly acknowledged.
文摘Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs.Consequently,a novel conformance control system HPF-Co gel,based on high-temperature stabilizer(CoCl_(2)·H_(2)O,CCH)is developed.The HPF-Co bulk gel has better performances with high temperature(120℃)and high salinity(1×10^(5)mg/L).According to Sydansk coding system,the gel strength of HPF-Co with CCH is increased to code G.The dehydration rate of HPF-Co gel is 32.0%after aging for 150 d at 120℃,showing excellent thermal stability.The rheological properties of HPF gel and HPF-Co gel are also studied.The results show that the storage modulus(G′)of HPF-Co gel is always greater than that of HPF gel.The effect of CCH on the microstructure of the gel is studied.The results show that the HPF-Co gel with CCH has a denser gel network,and the diameter of the three-dimensional network skeleton is 1.5-3.5μm.After 90 d of aging,HPF-Co gel still has a good three-dimensional structure.Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group,which can suppress the vibration of cross-linked sites and improve the stability at high temperature.Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system,plugging rate exceeding 98%.Moreover,the results of subsequent waterflooding recovery can be improved by 17%.
基金funded by the National Natural Science Foundation of China (No. 52174046)。
文摘Despite advances in renewable energy sources, the world's current infrastructure and consumption patterns still heavily depend on crude oil. Enhanced oil recovery(EOR) is a crucial method for significantly increasing the amount of crude oil extracted from mature and declining oil fields. Nanomaterials have shown great potential in improving EOR methods due to their unique properties, such as high surface area, tunable surface chemistry, and the ability to interact at the molecular level with fluids and rock surfaces. This study examines the potential use of incorporating ethoxylated molybdenum disulfide with a unique three-dimensional flower-like morphology for overcoming the challenges associated with oil recovery from reservoirs characterized by complex pore structures and low permeability. The synthesized nanomaterial features a chemical composition that encompasses a polar ethoxy group linking molybdenum disulfide nanosheets and an alkylamine chain. The ethoxy group promotes interactions with water molecules through hydrogen bonding and electrostatic forces, disrupting the cohesive forces among water molecules and reduction surface tension at the oil-water interface. As a result, the nanomaterial achieves an ultra-low interfacial tension of 10^(-3) mN/m. Core flooding experiments demonstrate a significant oil recovery of approximately 70% at a concentration as low as 50 ppm. This research paves the way for the design and synthesis of advanced extended surfactant-like nanomaterials,offering a promising avenue for enhancing oil recovery efficiency.
文摘A novel concept of treating oil reservoirs by nanofluids is being developed to improve oil recovery and reduce the trapped oil in hydrocarbon reservoirs.Nanoparticles show great potential in enhancing oil recovery under ambient conditions.In this paper,the approaches of wettability alteration by using nanofluid,stability of nanofluids,and the most reliable wettability alteration mechanisms associated with variant types of nanoparticles have been reviewed.Moreover,the parameters that have a significant influence on nanofluid flooding have been discussed.Finally,the recent studies of the effect of nanoparticles on wettability alteration have been summarised and analysed.Furthermore,this paper presents possible opportunities and challenges regarding wettability alteration using nanofluids.
基金financial support of the Science Foundation of China University of PetroleumBeijing(Grant No.2462020XKBH013)+1 种基金Financial supports from the National Natural Science Foundation of China(Grant No.51804316)the Science Foundation of China University of Petroleum,Beijing(Grant No.2462017YJRC037)
文摘Nanofluid offers more opportunities and challenges over the traditional surfactant and polymer solutions during enhanced oil recovery(commonly referred to as tertiary oil recovery)due to its remarkable properties.This review mainly discusses the preparation methods of amphiphilic nanoparticles due to their higher interface activity than sole hydrophilic or hydrophobic nanoparticles(SHNPs).The nanofluids’stability is reviewed in this work.Moreover,the mechanisms of nanofluids in enhancing oil recovery(N-EOR)in terms of interfacial tension reduction,wettability alteration,foam stabilization,emulsion stabilization,structural disjoining pressure,and depressurization-increasing injection are mainly summarized and reviewed.Also,the synergistic effects of nanofluids and traditional surfactants and polymers are discussed.Finally,nanofluids’challenges and prospects are also outlined.The nanofluids can still be regarded as an outstanding candidate for enhancing oil recovery significantly in the future although there are limitations on their applications from laboratory scale to field scale.
基金supported by China National Science and Technology Major Project(2011ZX05009-004,2011ZX05014-003)National Key Basic Research and Development Program(973 Program),China(2011CB201006)Science Foundation of China University of Petroleum,Beijing(2462014YJRC053)
文摘With complex fractured-vuggy heterogeneous structures, water has to be injected to facilitate oil pro- duction. However, the effect of different water injection modes on oil recovery varies. The limitation of existing numerical simulation methods in representing fractured- vuggy carbonate reservoirs makes numerical simulation difficult to characterize the fluid flow in these reservoirs. In this paper, based on a geological example unit in the Tahe Oilfield, a three-dimensional physical model was designed and constructed to simulate fluid flow in a fractured-vuggy reservoir according to similarity criteria. The model was validated by simulating a bottom water drive reservoir, and then subsequent water injection modes were optimized. These were continuous （constant rate）, intermittent, and pulsed injection of water. Experimental results reveal that due to the unbalanced formation pressure caused by pulsed water injection, the swept volume was expanded and consequently the highest oil recovery increment was achieved. Similar to continuous water injection, intermit- tent injection was influenced by factors including the connectivity of the fractured-vuggy reservoir, well depth, and the injection-production relationship, which led to a relative low oil recovery. This study may provide a constructive guide to field production and for the devel- opment of the commercial numerical models specialized for fractured-vuggy carbonate reservoirs.
基金the financial support from National Natural Science Foundation of China(51504268)National Technology Major Project of China(2016ZX05014).
文摘Gas injection serves as a main enhanced oil recovery(EOR)method in fractured-vuggy carbonate reservoir,but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configuration.Many researchers conducted experiments for the observation of fluid flow and the evaluation of production performance,while most of their physical models were fabricated based on the probability distribution of fractures and caves in the reservoir.In this study,a two-dimensional physical model of the karst fault system was designed and fabricated based on the geological model of TK748 well group in the seventh block of the Tahe Oilfield.The fluid flow and production performance of primary gas flooding were discussed.Gas-assisted gravity flooding was firstly introduced to take full use of gas-oil gravity difference,and its feasibility in the karst fault system was examined.Experimental results showed that primary gas flooding created more flow paths and achieved a remarkable increment of oil recovery compared to water flooding.Gas injection at a lower location was recommended to delay gas breakthrough.Gas-assisted gravity flooding achieved more stable gas-displacing-oil because oil production was at a lower location,and thus,the oil recovery was further enhanced.
基金supported by Project of Sinopec Northwest Oilfield Company(Grant No.202108ZB0046).
文摘The development of fractured-vuggy carbonate reservoirs is extremely difficult because of the complex fractured-vuggy structure and strong heterogeneity.Foam flooding is a potential enhanced oil recovery(EOR)technology in fractured-vuggy carbonate reservoirs.Based on the similarity criterion,three types of 2D visual physical models of the fractured-vuggy structure were made by laser ablation technique,and a 3D visual physical model of the fractured-vuggy reservoir was made by 3D printing technology.Then the physical analog experiments of foam flooding were carried out in these models.The experimental results show that foam can effectively improve the mobility ratio,control the flow velocity of the fluid in different directions,and sweep complex fracture networks.The effect of foam flooding in fractures can be improved by increasing foam strength and enhancing foam stability.The effect of foam flooding in vugs can be improved by reducing the density of the foam and the interfacial tension between foam and oil.Three types of microscopic residual oil and three types of macroscopic residual oil can be displaced by foam flooding.This study verifies the EOR of foam flooding in the fractured-vuggy reservoir and provides theoretical support for the application of foam flooding in fractured-vuggy 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supported by the Natural Science Foundation of Xinjiang Uygur Autonomous Region(No.2022D01A250)the CNPC Strategic Cooperation Science and Technology Project(ZLZX2020-01-04-04).
文摘Nanoparticles have been widely used in polymer gel systems in recent years to improve gelation performance under high-temperature reservoir conditions. However, different types of nanoparticles have different effects on their gelation performance, which has been little researched. In this study, the high-temperature gelation performance, chemical structure, and microstructure of polymer gels prepared from two nanomaterials (i.e., nano-SiO_(2) and nano-TiO_(2)) were measured. The conventional HPAM/PEI polymer gel system was employed as the control sample. Results showed that the addition of nano-TiO_(2) could significantly enhance the gel strength of HPAM/PEI gel at 80 ℃. The gel strength of the enhanced HPAM/PEI gel with 0.1 wt% nano-TiO_(2) could reach grade I. The system also had excellent high-temperature stability at 150 ℃. The enhanced HPAM/PEI gel with 0.02 wt% nano-TiO_(2) reached the maximum gel strength at 150 ℃ with a storage modulus (G′) of 15 Pa, which can meet the need for efficient plugging. However, the nano-SiO_(2) enhanced HPAM/PEI polymer gel system showed weaker gel strength than that with nano-TiO_(2) at both 80 and 150 ℃ with G′ lower than 5 Pa. Microstructures showed that the nano-TiO_(2) enhanced HPAM/PEI gel had denser three-dimensional (3D) mesh structures, which makes the nano-TiO_(2) enhanced HPAM/PEI gel more firmly bound to water. The FT-IR results also confirmed that the chemical structure of the nano-TiO_(2) enhanced HPAM/PEI gel was more thermally stable than nano-SiO_(2) since there was a large amount of –OH groups on the structure surface. Therefore, nano-TiO_(2) was more suitable as the reinforcing material for HPAM/PEI gels for high-temperature petroleum reservoir conformance improvement.
基金financial support of the Science Foundation of China University of Petroleum,Beijing(Grant No.2462020XKBH013)The Science Foundation of China University of Petroleum,Beijing(Grant No.2462017YJRC037)+1 种基金Sponsored by CNPC Innovation Found(Grant No.2021DQ02-0202)Horizontal project of Sinopec Northwest Oilfield Company(Grant No.202108ZB0046)are also significantly acknowledged
文摘Plugging agents have been widely used to enhance oil recovery in fractured-vuggy carbonate reservoirs.However,the harsh conditions of fractured-vuggy carbonate reservoirs yield a significant challenge in maintaining a long-term stabilization of plugging agents.In this work,we developed an anti-hightemperature and high-salinity polymer gel(APG)with excellent resistance to high temperature(140℃)and ultra-high salinity(240000 mg/L).The rheology and microstructure of APG were characterized before and after gelation.Core plugging tests on fractured cubic cores were conducted to quantify the plugging performance of the gel system.Experimental results showed that the Sclerglucan and Cobalt(Ⅱ)Chloride Hexahydrate filled the three-dimensional(3-D)network with various morphologies,providing extra protection to the cross-linking points of the 3D network structure of APG and thus,leading to a prolongation of the dehydration time.The dehydration rate of APG was only 5%within 30days,and the strength of APG could be maintained at a rigid or near-rigid level over 150 days.Moreover,APG exhibited satisfactory shear and scour resistance.Core plugging tests showed that APG could achieve a plugging rate of 90%and demonstrate ignorable minor damage to the substrate.Our results indicate that APG can serve as a great candidate in channel plugging in fractured-vuggy carbonate reservoirs where fractures are fully developed.
基金This study is financially supported by CNPC Innovation Foundation(2020D-5007-0214)Major Strategic Project of CNPC(ZLZX2020-01-04)Beijing Municipal Excellent Talent Training Funds Youth Advanced Individual Project(2018000020124G163)。
文摘Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs,owing to its advantages in reducing oil viscosity,improving mobility ratio,quickly replenishing formation pressure,and potentially achieving a miscible state.However,reliable inhouse laboratory evaluation of CO_(2) huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure.In this study,we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO_(2) injection in a tight conglomerate reservoir.The impacts of depletion degree,pore volume injection of CO_(2) and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure.Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency(first increased and then decreased)with increased CO_(2) injection volume and soaking time.The lower oil recoveries under excess CO_(2) injection and soaking time were attributed to limited CO_(2) dissolution and asphaltene precipitation.This work guides secure and reliable laboratory design of CO_(2) huff-n-puff in tight reservoirs with high formation pressure.
基金supports from the National Natural Science Foundation of China(Grant No.52474059,Grant No.52174046)are greatly acknowledged.
文摘Fine particle detachment and subsequent migration can lead to severe pore plugging and consequent permeability decline.Therefore,it is crucial to quantify the critical condition when fine particle detachment occurs.The frequently observed deviations or even contradictions between experimental results and theoretical predictions of fines detachment arise from an insufficient understanding of adhesion force that can be highly influenced by salinity and temperature.To clarify the intrinsic influence of salinity and temperature on fines detachment,adhesion forces between carboxyl microspheres and hydrophilic silica substrates in an aqueous medium were measured at various salinities and tempera-tures using atomic force microscopy(AFM).The AFM-measured adhesion force decreases with increasing salinity or temperature.Trends of mean measured adhesion forces with temperature and salinity were compared with the DLVO and XDLVO theories.DLVO theory captured the trend with temperature via the impact of temperature on electric double layer interactions,whereas XDLVO theory captured the observed trend with salinity via the impact of salinity on the repulsive hydration force.Our results highlight the significance of hydration force in accurately predicting the fate of fines in porous media.
