CO_(2) flooding is a vital development method for enhanced oil recovery in low-permeability reservoirs,However,micro-fractures are developed in low-permeability reservoirs,which are essential oil flow channels but can...CO_(2) flooding is a vital development method for enhanced oil recovery in low-permeability reservoirs,However,micro-fractures are developed in low-permeability reservoirs,which are essential oil flow channels but can also cause severe CO_(2) gas channeling problems.Therefore,anti-gas channeling is a necessary measure to improve the effect of CO_(2) flooding.The kind of anti-gas channeling refers to the plugging of fractures in the deep formation to prevent CO_(2) gas channeling,which is different from the wellbore leakage.Polymer microspheres have the characteristics of controllable deep plugging,which can achieve the profile control of low-permeability fractured reservoirs.In acidic environments with supercritical CO_(2),traditional polymer microspheres have poor expandability and plugging properties.Based on previous work,a systematic evaluation of the expansion performance,dispersion rheological properties,stability,deep migration,anti-CO_(2) channeling and enhanced oil recovery ability of a novel acid-resistant polymer microsphere(DCNPM-A)was carried out under CQ oilifield conditions(salinity of85,000 mg/L,80℃,pH=3).The results show that the DCNPM-A microsphere had a better expansion performance than the traditional microsphere,with a swelling rate of 13.5.The microsphere dispersion with a concentration of 0.1%-0.5%had the advantages of low viscosity,high dispersion and good injectability in the low permeability fractured core.In the acidic environment of supercritical CO_(2),DCNPM-A microspheres showed excellent stability and could maintain strength for over 60 d with less loss.In core experiments,DCNPM-A microspheres exhibited delayed swelling characteristics and could effectively plug deep formations.With a plugging rate of 95%,the subsequent enhanced oil recovery of CO_(2) flooding could reach 21.03%.The experimental results can provide a theoretical basis for anti-CO_(2)channeling and enhanced oil recovery in low-permeability fractured reservoirs.展开更多
Spontaneous imbibition(SI)is an important mechanism for enhancing oil recovery in low-permeability reservoirs.Due to the strong heterogeneity,and the non-Darcy flow,the construction of SI model for lowpermeability res...Spontaneous imbibition(SI)is an important mechanism for enhancing oil recovery in low-permeability reservoirs.Due to the strong heterogeneity,and the non-Darcy flow,the construction of SI model for lowpermeability reservoirs is extremely challenging.Commonly,traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure(TP)on imbibition.Therefore,in this work,based on capillary model and fractal theory,a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established.On this basis,the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil.The proposed new SI model was verified by imbibition experimental data.The study shows that for weakly heterogeneous cores with permeability of 0-1 m D,the traditional SI model can characterize the imbibition process relatively accurately,and the new imbibition model can increase the coefficient of determination by 1.05 times.However,traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10-50 m D.The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem,and the determination coefficient is increased from 0.344 to 0.922,which is increased by2.68 times.For low-permeability reservoirs,the production of the oil in transitional pores(0.01-0.1μm)and mesopores(0.1-1μm)significantly affects the imbibition recovery,as the research shows that when the heterogeneity of pore seepage channels is ignored,the oil recovery in transitional pores and mesopores decreases by 7.54%and 4.26%,respectively.Sensitivity analysis shows that increasing interfacial tension,decreasing contact angle,oil-water viscosity ratio and threshold pressure will increase imbibition recovery.In addition,there are critical values for the influence of these factors on the imbibition recovery,which provides theoretical support for surfactant optimization.展开更多
As the traditional polymer stabilizer is eliminated to improve the injectability of foam in lowpermeability reservoirs,the stability,plugging capacity,conformance control and oil recovery performance of the surfactant...As the traditional polymer stabilizer is eliminated to improve the injectability of foam in lowpermeability reservoirs,the stability,plugging capacity,conformance control and oil recovery performance of the surfactant-alternating-gas(SAG)foam become significantly important for determining its adaptability to permeability and heterogeneity,which were focused and experimentally researched in this paper.Results show that the SAG bubbles are highly stable in micron-sized channels and porous media(than in the conventional unconstrained graduated cylinder),making it possible to use in enhanced oil recovery(EOR).Such bubbles formed in porous media could be passively adjusted to match their diameter with the size of the pore.This endows the SAG foam with underlying excellent injectability and deep migration capacity.Permeability adaptability results indicate a reduced plugging capacity,but,increased incremental oil recovery by the SAG foam with decreased permeability.This makes it a good candidate for EOR over a wide range of permeability,however,parallel core floods demonstrate that there is a limiting heterogeneity for SAG application,which is determined to be a permeability contrast of 12.0(for a reservoir containing oil of 9.9 m Pa s).Beyond this limit,the foam would become ineffective.展开更多
Nanocellulose,a natural polymeric nanomaterial,has attracted significant attention in enhanced oil recovery(EOR)applications due to its abundance,nanoscale,high oil-water interfacial adsorption ef-ficiency.In this stu...Nanocellulose,a natural polymeric nanomaterial,has attracted significant attention in enhanced oil recovery(EOR)applications due to its abundance,nanoscale,high oil-water interfacial adsorption ef-ficiency.In this study,surface-functionalized cellulose nanocrystals(SF-CNCs)were prepared via hy-drochloric acid hydrolysis and chemical modification,with adaptable nanosize and considerable dispersion stability in low-permeability reservoirs.The SF-CNCs were structurally characterized by FT-IR,Cryo-TEM,which have a diameter of 5-10 nm and a length of 100-200 nm.The SF-CNC dispersions possessed higher stability and stronger salt-tolerance than those of corresponding CNC dispersions,due to the strong hydrophilicity of the sulfonic acid group.It was synergistically used with a non-ionic surfactant(APG1214)to formulate a combined flooding system(0.1 wt%SF-CNC+0.2 wt%APG1214).The combined flooding system exhibits strong emulsification stability,low oil-water interfacial tension of o.03 mN/m,and the ability to alter the wettability for oil-wetting rocks.Furthermore,the combined system was_able to provide an optimum EOR efficiency of 20.2%in low-permeability cores with 30.13×10^(-3)μm^(2).Notably.it can enlarge the sweep volume and increase the displacement efficiency simultaneously.Overall,the newly formulated nanocellulose/surfactant combined system exhibits a remarkable EoR performance in low-permeability 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
At high cycles of steam huff&puff,oil distribution in reservoirs becomes stronger heterogeneity due to steam channeling.Thermal solidification agent can be used to solve this problem.Its solution is a lowviscosity...At high cycles of steam huff&puff,oil distribution in reservoirs becomes stronger heterogeneity due to steam channeling.Thermal solidification agent can be used to solve this problem.Its solution is a lowviscosity liquid at normal temperature,but it can be solidified above 80℃.The plugging degree is up to 99%at 250℃.The sweep efficiency reaches 59.2%,which is 7.3%higher than pure steam injection.In addition,simultaneous injection of viscosity reducer and/or nitrogen foams can further enhance oil recovery.The mechanism of this technology depends on its strong plugging ability,which changes the flowing pattern of steam to effectively mobilize remaining oil.Viscosity reducer and nitrogen foams further expand the sweep range and extends the effective period.Therefore,thermal solidification agent can plug steam channeling paths and adjust steam flowing direction to significantly enhance oil recovery at high cycles of steam huff&puff.展开更多
Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or ca...Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil （gas） saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone （oil displacing water）, we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that： 1） Oil migration （oil displacing water） in low- permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2） With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity up＂ non-Darcy percolation curve; 3） Oil-water is less than 1.0, the percolation curve is a ＂concave- two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4） The oil saturation of low- permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.展开更多
Deep oil and gas reservoirs are under high-temperature conditions,but traditional coring methods do not consider temperature-preserved measures and ignore the influence of temperature on rock porosity and permeability...Deep oil and gas reservoirs are under high-temperature conditions,but traditional coring methods do not consider temperature-preserved measures and ignore the influence of temperature on rock porosity and permeability,resulting in distorted resource assessments.The development of in situ temperaturepreserved coring(ITP-Coring)technology for deep reservoir rock is urgent,and thermal insulation materials are key.Therefore,hollow glass microsphere/epoxy resin thermal insulation materials(HGM/EP materials)were proposed as thermal insulation materials.The materials properties under coupled hightemperature and high-pressure(HTHP)conditions were tested.The results indicated that high pressures led to HGM destruction and that the materials water absorption significantly increased;additionally,increasing temperature accelerated the process.High temperatures directly caused the thermal conductivity of the materials to increase;additionally,the thermal conduction and convection of water caused by high pressures led to an exponential increase in the thermal conductivity.High temperatures weakened the matrix,and high pressures destroyed the HGM,which resulted in a decrease in the tensile mechanical properties of the materials.The materials entered the high elastic state at 150℃,and the mechanical properties were weakened more obviously,while the pressure led to a significant effect when the water absorption was above 10%.Meanwhile,the tensile strength/strain were 13.62 MPa/1.3%and 6.09 MPa/0.86%at 100℃ and 100 MPa,respectively,which meet the application requirements of the self-designed coring device.Finally,K46-f40 and K46-f50 HGM/EP materials were proven to be suitable for ITP-Coring under coupled conditions below 100℃ and 100 MPa.To further improve the materials properties,the interface layer and EP matrix should be optimized.The results can provide references for the optimization and engineering application of materials and thus technical support for deep oil and gas resource development.展开更多
In recent years,supercritical CO_(2)flooding has become an effective method for developing lowpermeability reservoirs.In supercritical CO_(2)flooding different factors influence the mechanism of its displacement proce...In recent years,supercritical CO_(2)flooding has become an effective method for developing lowpermeability reservoirs.In supercritical CO_(2)flooding different factors influence the mechanism of its displacement process for oil recovery.Asynchronous injection-production modes can use supercritical CO_(2)to enhance oil recovery but may also worsen the injection capacity.Cores with high permeability have higher oil recovery rates and better injection capacity,however,gas channeling occurs.Supercritical CO_(2)flooding has a higher oil recovery at high pressure levels,which delays the occurrence of gas channeling.Conversely,gas injection has lower displacement efficiency but better injection capacity at the high water cut stage.This study analyzes the displacement characteristics of supercritical CO_(2)flooding with a series of experiments under different injection and production parameters.Experimental results show that the gas breakthrough stage has the fastest oil production and the supercritical CO_(2)injection capacity variation tendency is closely related to the gas-oil ratio.Further experiments show that higher injection rates represent significant ultimate oil recovery and injection index,providing a good reference for developing low-permeability reservoirs.展开更多
The genesis of a reservoir is a result of the combined action of deposition, diagenesis, tectonic reworking, and interaction of rock and fluid and the evolutionary environment. We discuss the genetic and evolution mec...The genesis of a reservoir is a result of the combined action of deposition, diagenesis, tectonic reworking, and interaction of rock and fluid and the evolutionary environment. We discuss the genetic and evolution mechanism of a low-permeability reservoir bed of the Xujiahe Formation in the western Sichuan Depression on the basis of the study of diagenesis, diagenetic reservoir facies and the diagenetic evolution sequence. The research indicated that this reservoir bed can be divided into five types of diagenetic reservoir facies, namely strong dissolution, chlorite-lined intergranular pores, compaction and pressure solution, carbonate cementation and secondary quartz increase. There are, however, just two diagenetic reservoir facies which provide low-permeability reservoir beds, namely strong dissolution and chlorite-lined intergranular pores. We also analyzed their diagenetic evolution sequences and the origin of the low-permeability reservoir bed. Besides, it was also indicated that the composition and structure of sandstones, types of sedimentary microfacies, diagenesis history as well as the tectonic reworking in later periods are the main factors controlling the formation of the low-permeability reservoir bed. The above- mentioned factors establish the foundation for the forecasting the distribution of high quality reservoir beds.展开更多
According to the geological characteristics and their influential factors of the low-permeability reservoirs, a comprehensive method for evaluation of low-permeability reservoirs is put forward. The method takes a mat...According to the geological characteristics and their influential factors of the low-permeability reservoirs, a comprehensive method for evaluation of low-permeability reservoirs is put forward. The method takes a matrix system as the basis, a fracture system as the focus and a stress field system as the restricted factor. It can objectively reflect not only the storage capability and seepage capability of low-permeability reservoirs, but also the effect on development as well. At the same time, it can predict the seepage characteristics at different development stages and provide a reasonable geological basis for the development of low-permeability reservoirs.展开更多
This paper discusses the systematic design and development of low-damage drilling fluid to protect the low-permeability gas reservoir of the Sulige block in the Ordos Basin, Inner Mongolia Autonomous Region, China. Ba...This paper discusses the systematic design and development of low-damage drilling fluid to protect the low-permeability gas reservoir of the Sulige block in the Ordos Basin, Inner Mongolia Autonomous Region, China. Based on investigation of the geological characteristics and the potential formation damage of the Permian formation of the reservoir, waterblocking due to invasion of drilling or completion fluids was identified one of the most severe causes of damage to gas well deliverability. By adopting the phase trap prevention method, ideal packing theory, and film-forming technology, a lowdamage drilling fluid, sodium formate brine containing efficient waterblocking preventing surfactants, optimized temporary bridging agents （TBAs）, and film-forming agents has been developed. The performance of the new drilling fluid was evaluated by using a variety of techniques. The results show that the fluid has good rheological properties, good strong shale-swelling inhibition, good temporary plugging effect, ultra-low filtration, and good lubricity. It can efficiently minimize waterblocking and can be used to drill horizontal wells with minimal intervention of the reservoir in the Sulige Gas Field.展开更多
The intensive development of tight reservoirs has positioned them as a strategic alternative to conventional oil and gas resources. Existing enhanced oil recovery(EOR) methods struggle to effectively exploring reservo...The intensive development of tight reservoirs has positioned them as a strategic alternative to conventional oil and gas resources. Existing enhanced oil recovery(EOR) methods struggle to effectively exploring reservoir oil, resulting in low recovery rates. Novel and effective means of developing tight reservoirs are urgently needed. Nanomaterials have shown promising applications in improving water flooding efficiency, with in-depth research into mechanisms that lower injection pressure and increase water injection volumes. However, the extent of improvement remains limited. In this study, a silicon quantum dots(Si-QDs) material was synthesized via a hydrothermal synthesis method and used to prepare a nanofluid for the efficient recovery of tight reservoir. The Si-QDs, with an approximate diameter of 3 nm and a spherical structure, were surface functionalized with benzenesulfonic acid groups to enhance the performance. The developed nanofluid demonstrated stability without aggregation at 120℃ and a salinity of 60000 mg/L. Core flooding experiments have demonstrated the attractive EOR capabilities of Si-QDs, shedding light of the EOR mechanisms. Si-QDs effectively improve the wettability of rocks, enhancing the sweeping coefficient of injected fluids and expanding sweeping area.Within this sweeping region, Si-QDs efficiently stripping adsorbed oil from the matrix, thus increasing sweeping efficiency. Furthermore, Si-QDs could modify the state of pore-confined crude oil, breaking it down into smaller particles that are easier to displacement in subsequent stages. Si-QDs exhibit compelling EOR potential, positioning them as a promising approach for effectively developing tight oil reservoirs.展开更多
Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Bas...Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.展开更多
Polymerflooding is an effective method widely applied for enhancing oil recovery(EOR)by reducing the mobility ratio between theinjected water and crude oil.However,traditional polymers encounter challenges in high sali...Polymerflooding is an effective method widely applied for enhancing oil recovery(EOR)by reducing the mobility ratio between theinjected water and crude oil.However,traditional polymers encounter challenges in high salinity reservoirs due to their salt sensitivity.Toovercome this challenge,we synthesized a zwitterion polymer(PAMNS)with salt-induced tackifying property through copolymerization ofacrylamide and a zwitterion monomer,methylacrylamide propyl-N,N-dimethylbutylsulfonate(NS).NS monomer is obtained from thereaction between 1,4-butanesultone and dimethylamino propyl methylacrylamide.In this study,the rheological properties,salt responsiveness,and EOR efficiency of PAMNS were evaluated.Results demonstrate that PAMNS exhibits desirable salt-induced tackifyingcharacteristics,with viscosity increasing up to 2.4 times as the NaCl concentration reaches a salinity of 30×10^(4)mg L^(-1).Furthermore,highvalence ions possess a much stronger effect on enhancing viscosity,manifested as Mg^(2+)>Ca^(2+)>Na^(+).Molecular dynamics simulations(MD)andfluid dynamics experiment results demonstrate that PAMNS molecules exhibit a more stretched state and enhanced intermolecularassociations in high-salinity environments.It is because of the salt-induced tackifying,PAMNS demonstrates superior performance inpolymerflooding experiments under salinity ranges from 5×10^(4)mg L^(-1)to 20×10^(4)mg L^(-1),leading to 10.38–19.83%higher EOR thantraditional polymers.展开更多
Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imb...Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.展开更多
Supercritical CO_(2)(SC-CO_(2)) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO_(2) hybrid fracturin...Supercritical CO_(2)(SC-CO_(2)) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO_(2) hybrid fracturing method has been proposed, which combines the advantages of SC-CO_(2) fracturing and hydraulic fracturing. However, the specific impacts of different pre-SC-CO_(2) injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO_(2) injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO_(2) injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO_(2) leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO_(2) injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO_(2) is positively correlated with the injection displacement and volume.Additionally, pre-injection of SC-CO_(2) enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO_(2) injection parameters.Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO_(2) hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO_(2) injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of pre SC-CO_(2) hybrid fracturing in shale oil reservoirs.展开更多
Countercurrent imbibition is an important mechanism for tight oil recovery,that is,water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture.Its significance over...Countercurrent imbibition is an important mechanism for tight oil recovery,that is,water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture.Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces.We used the computed tomography(CT)scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance(CID)at different fluid pressures,initial water saturations,and permeability.Surprisingly,experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule(i.e.,evolutes proportional to square root of time,t^(0.5)).At early stage,CID extends faster than t^(0.5)(super-diffusive);while at late stage,CID extends much slower than t^(0.5)(sub-diffusive).After tens of hours,the CID change becomes too slow to be practically efficient for tight oil recovery.This research demonstrates that this deviation from classic theory is a result of(1)a much longer characteristic capillary length than effective invasion depth,which eliminates full development of a classical displacement front;and(2)non-zero flow at low water saturation,which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks.To well depict the details of the imbibition front in this situation,we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations,which successfully rationalizes the non-diffusive behavior and fits experimental data.Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition,beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery(EOR)strategy than soaking for longer time.展开更多
Under the policy background and advocacy of carbon capture,utilization,and storage(CCUS),CO_(2)-EOR has become a promising direction in the shale oil reservoir industry.The multi-scale pore structure distribution and ...Under the policy background and advocacy of carbon capture,utilization,and storage(CCUS),CO_(2)-EOR has become a promising direction in the shale oil reservoir industry.The multi-scale pore structure distribution and fracture structure lead to complex multiphase flow,comprehensively considering multiple mechanisms is crucial for development and CO_(2) storage in fractured shale reservoirs.In this paper,a multi-mechanism coupled model is developed by MATLAB.Compared to the traditional Eclipse300 and MATLAB Reservoir Simulation Toolbox(MRST),this model considers the impact of pore structure on fluid phase behavior by the modified Peng—Robinson equation of state(PR-EOS),and the effect simultaneously radiate to Maxwell—Stefan(M—S)diffusion,stress sensitivity,the nano-confinement(NC)effect.Moreover,a modified embedded discrete fracture model(EDFM)is used to model the complex fractures,which optimizes connection types and half-transmissibility calculation approaches between non-neighboring connections(NNCs).The full implicit equation adopts the finite volume method(FVM)and Newton—Raphson iteration for discretization and solution.The model verification with the Eclipse300 and MRST is satisfactory.The results show that the interaction between the mechanisms significantly affects the production performance and storage characteristics.The effect of molecular diffusion may be overestimated in oil-dominated(liquid-dominated)shale reservoirs.The well spacing and injection gas rate are the most crucial factors affecting the production by sensitivity analysis.Moreover,the potential gas invasion risk is mentioned.This model provides a reliable theoretical basis for CO_(2)-EOR and sequestration in shale oil reservoirs.展开更多
Based on the geochemical,seismic,logging and drilling data,the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics...Based on the geochemical,seismic,logging and drilling data,the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics,the tight oil enrichment model and its major controlling factors.First,the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation,with the development of nose structure around sag and the broad and continuous distribution of sand bodies.The reservoirs are tight on the whole.Second,the configuration of multiple elements,such as high-quality source rocks,reservoir rocks,fault,overpressure and structure,controls the tight oil enrichment in the Fuyu reservoirs.The source-reservoir combination controls the tight oil distribution pattern.The pressure difference between source and reservoir drives the charging of tight oil.The fault-sandbody transport system determines the migration and accumulation of oil and gas.The positive structure is the favorable place for tight oil enrichment,and the fault-horst zone is the key part of syncline area for tight oil exploration.Third,based on the source-reservoir relationship,transport mode,accumulation dynamics and other elements,three tight oil enrichment models are recognized in the Fuyu reservoirs:(1)vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks,that is,driven by overpressure,hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks;(2)transport of hydrocarbon through faults between separated source and reservoirs,that is,driven by overpressure,hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks;and(3)migration of hydrocarbon through faults and sandbodies between separated source and reservoirs,that is,driven by overpressure,hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks,and then migrates laterally through sandbodies.Fourth,the differences in oil source conditions,charging drive,fault distribution,sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs.Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Sag has good conditions for tight oil enrichment and has been less explored,and it is an important new zone for tight oil exploration in the future.展开更多
基金supported by the Fund of State Key Laboratory of Deep Oil and Gas,China University of Petroleum (East China) (SKLDOG2024-ZYRC-06)Key Program of National Natural Science Foundation of China (52130401)+2 种基金National Natural Science Foundation of China (52104055,52250410349)Major Science and Technology Project of China National Petroleum Corporation Limited (2021ZZ01-08)Shandong Provincial Natural Science Foundation,China (ZR2021ME171)。
文摘CO_(2) flooding is a vital development method for enhanced oil recovery in low-permeability reservoirs,However,micro-fractures are developed in low-permeability reservoirs,which are essential oil flow channels but can also cause severe CO_(2) gas channeling problems.Therefore,anti-gas channeling is a necessary measure to improve the effect of CO_(2) flooding.The kind of anti-gas channeling refers to the plugging of fractures in the deep formation to prevent CO_(2) gas channeling,which is different from the wellbore leakage.Polymer microspheres have the characteristics of controllable deep plugging,which can achieve the profile control of low-permeability fractured reservoirs.In acidic environments with supercritical CO_(2),traditional polymer microspheres have poor expandability and plugging properties.Based on previous work,a systematic evaluation of the expansion performance,dispersion rheological properties,stability,deep migration,anti-CO_(2) channeling and enhanced oil recovery ability of a novel acid-resistant polymer microsphere(DCNPM-A)was carried out under CQ oilifield conditions(salinity of85,000 mg/L,80℃,pH=3).The results show that the DCNPM-A microsphere had a better expansion performance than the traditional microsphere,with a swelling rate of 13.5.The microsphere dispersion with a concentration of 0.1%-0.5%had the advantages of low viscosity,high dispersion and good injectability in the low permeability fractured core.In the acidic environment of supercritical CO_(2),DCNPM-A microspheres showed excellent stability and could maintain strength for over 60 d with less loss.In core experiments,DCNPM-A microspheres exhibited delayed swelling characteristics and could effectively plug deep formations.With a plugging rate of 95%,the subsequent enhanced oil recovery of CO_(2) flooding could reach 21.03%.The experimental results can provide a theoretical basis for anti-CO_(2)channeling and enhanced oil recovery in low-permeability fractured reservoirs.
基金supported by China Natural Science Foundation(Grant No.52274053)Beijing Natural Science Foundation(Grant No.3232028)Open Fund of State Key Laboratory of Offshore Oil Exploitation(Grant No.CCL2021RCPS0515KQN)。
文摘Spontaneous imbibition(SI)is an important mechanism for enhancing oil recovery in low-permeability reservoirs.Due to the strong heterogeneity,and the non-Darcy flow,the construction of SI model for lowpermeability reservoirs is extremely challenging.Commonly,traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure(TP)on imbibition.Therefore,in this work,based on capillary model and fractal theory,a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established.On this basis,the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil.The proposed new SI model was verified by imbibition experimental data.The study shows that for weakly heterogeneous cores with permeability of 0-1 m D,the traditional SI model can characterize the imbibition process relatively accurately,and the new imbibition model can increase the coefficient of determination by 1.05 times.However,traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10-50 m D.The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem,and the determination coefficient is increased from 0.344 to 0.922,which is increased by2.68 times.For low-permeability reservoirs,the production of the oil in transitional pores(0.01-0.1μm)and mesopores(0.1-1μm)significantly affects the imbibition recovery,as the research shows that when the heterogeneity of pore seepage channels is ignored,the oil recovery in transitional pores and mesopores decreases by 7.54%and 4.26%,respectively.Sensitivity analysis shows that increasing interfacial tension,decreasing contact angle,oil-water viscosity ratio and threshold pressure will increase imbibition recovery.In addition,there are critical values for the influence of these factors on the imbibition recovery,which provides theoretical support for surfactant optimization.
基金the Natural Science Foundation of Shandong Province of China(Grant No.ZR2020ME089)the National Natural Science Foundation of China(Grant No.51504275 and 5207433)for their financial supports
文摘As the traditional polymer stabilizer is eliminated to improve the injectability of foam in lowpermeability reservoirs,the stability,plugging capacity,conformance control and oil recovery performance of the surfactant-alternating-gas(SAG)foam become significantly important for determining its adaptability to permeability and heterogeneity,which were focused and experimentally researched in this paper.Results show that the SAG bubbles are highly stable in micron-sized channels and porous media(than in the conventional unconstrained graduated cylinder),making it possible to use in enhanced oil recovery(EOR).Such bubbles formed in porous media could be passively adjusted to match their diameter with the size of the pore.This endows the SAG foam with underlying excellent injectability and deep migration capacity.Permeability adaptability results indicate a reduced plugging capacity,but,increased incremental oil recovery by the SAG foam with decreased permeability.This makes it a good candidate for EOR over a wide range of permeability,however,parallel core floods demonstrate that there is a limiting heterogeneity for SAG application,which is determined to be a permeability contrast of 12.0(for a reservoir containing oil of 9.9 m Pa s).Beyond this limit,the foam would become ineffective.
基金the China National Postdoctoral Program for Innovative Talents(Bx20200386)China Postdoctoral Science Foundation(2021M703586)+1 种基金Key Program of National Natural Science Foundation of China(52130401)National Natural Science Foundation of China(52204064,52104055)for financial support.
文摘Nanocellulose,a natural polymeric nanomaterial,has attracted significant attention in enhanced oil recovery(EOR)applications due to its abundance,nanoscale,high oil-water interfacial adsorption ef-ficiency.In this study,surface-functionalized cellulose nanocrystals(SF-CNCs)were prepared via hy-drochloric acid hydrolysis and chemical modification,with adaptable nanosize and considerable dispersion stability in low-permeability reservoirs.The SF-CNCs were structurally characterized by FT-IR,Cryo-TEM,which have a diameter of 5-10 nm and a length of 100-200 nm.The SF-CNC dispersions possessed higher stability and stronger salt-tolerance than those of corresponding CNC dispersions,due to the strong hydrophilicity of the sulfonic acid group.It was synergistically used with a non-ionic surfactant(APG1214)to formulate a combined flooding system(0.1 wt%SF-CNC+0.2 wt%APG1214).The combined flooding system exhibits strong emulsification stability,low oil-water interfacial tension of o.03 mN/m,and the ability to alter the wettability for oil-wetting rocks.Furthermore,the combined system was_able to provide an optimum EOR efficiency of 20.2%in low-permeability cores with 30.13×10^(-3)μm^(2).Notably.it can enlarge the sweep volume and increase the displacement efficiency simultaneously.Overall,the newly formulated nanocellulose/surfactant combined system exhibits a remarkable EoR performance in low-permeability 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supported by National Natural Science Foundation of China(52074321)Natural Science Foundation of Beijing Municipality,China(3192026)。
文摘At high cycles of steam huff&puff,oil distribution in reservoirs becomes stronger heterogeneity due to steam channeling.Thermal solidification agent can be used to solve this problem.Its solution is a lowviscosity liquid at normal temperature,but it can be solidified above 80℃.The plugging degree is up to 99%at 250℃.The sweep efficiency reaches 59.2%,which is 7.3%higher than pure steam injection.In addition,simultaneous injection of viscosity reducer and/or nitrogen foams can further enhance oil recovery.The mechanism of this technology depends on its strong plugging ability,which changes the flowing pattern of steam to effectively mobilize remaining oil.Viscosity reducer and nitrogen foams further expand the sweep range and extends the effective period.Therefore,thermal solidification agent can plug steam channeling paths and adjust steam flowing direction to significantly enhance oil recovery at high cycles of steam huff&puff.
基金supported by the National Natural Science Foundation Project (No.40772088)the National Basic Research Program ("973" Program,Grant No. 2006CB202305)
文摘Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil （gas） saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone （oil displacing water）, we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that： 1） Oil migration （oil displacing water） in low- permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2） With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity up＂ non-Darcy percolation curve; 3） Oil-water is less than 1.0, the percolation curve is a ＂concave- two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4） The oil saturation of low- permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.
基金supported by the Sichuan Science and Technology Program (Grant Nos.2023NSFSC0004,2023NSFSC0790)the National Natural Science Foundation of China (Grant Nos.51827901,52304033)the Sichuan University Postdoctoral Fund (Grant No.2024SCU12093)。
文摘Deep oil and gas reservoirs are under high-temperature conditions,but traditional coring methods do not consider temperature-preserved measures and ignore the influence of temperature on rock porosity and permeability,resulting in distorted resource assessments.The development of in situ temperaturepreserved coring(ITP-Coring)technology for deep reservoir rock is urgent,and thermal insulation materials are key.Therefore,hollow glass microsphere/epoxy resin thermal insulation materials(HGM/EP materials)were proposed as thermal insulation materials.The materials properties under coupled hightemperature and high-pressure(HTHP)conditions were tested.The results indicated that high pressures led to HGM destruction and that the materials water absorption significantly increased;additionally,increasing temperature accelerated the process.High temperatures directly caused the thermal conductivity of the materials to increase;additionally,the thermal conduction and convection of water caused by high pressures led to an exponential increase in the thermal conductivity.High temperatures weakened the matrix,and high pressures destroyed the HGM,which resulted in a decrease in the tensile mechanical properties of the materials.The materials entered the high elastic state at 150℃,and the mechanical properties were weakened more obviously,while the pressure led to a significant effect when the water absorption was above 10%.Meanwhile,the tensile strength/strain were 13.62 MPa/1.3%and 6.09 MPa/0.86%at 100℃ and 100 MPa,respectively,which meet the application requirements of the self-designed coring device.Finally,K46-f40 and K46-f50 HGM/EP materials were proven to be suitable for ITP-Coring under coupled conditions below 100℃ and 100 MPa.To further improve the materials properties,the interface layer and EP matrix should be optimized.The results can provide references for the optimization and engineering application of materials and thus technical support for deep oil and gas resource development.
基金financial support from the National Natural Science Foundation of China(No.51904324,51974348,U19B6003)
文摘In recent years,supercritical CO_(2)flooding has become an effective method for developing lowpermeability reservoirs.In supercritical CO_(2)flooding different factors influence the mechanism of its displacement process for oil recovery.Asynchronous injection-production modes can use supercritical CO_(2)to enhance oil recovery but may also worsen the injection capacity.Cores with high permeability have higher oil recovery rates and better injection capacity,however,gas channeling occurs.Supercritical CO_(2)flooding has a higher oil recovery at high pressure levels,which delays the occurrence of gas channeling.Conversely,gas injection has lower displacement efficiency but better injection capacity at the high water cut stage.This study analyzes the displacement characteristics of supercritical CO_(2)flooding with a series of experiments under different injection and production parameters.Experimental results show that the gas breakthrough stage has the fastest oil production and the supercritical CO_(2)injection capacity variation tendency is closely related to the gas-oil ratio.Further experiments show that higher injection rates represent significant ultimate oil recovery and injection index,providing a good reference for developing low-permeability reservoirs.
文摘The genesis of a reservoir is a result of the combined action of deposition, diagenesis, tectonic reworking, and interaction of rock and fluid and the evolutionary environment. We discuss the genetic and evolution mechanism of a low-permeability reservoir bed of the Xujiahe Formation in the western Sichuan Depression on the basis of the study of diagenesis, diagenetic reservoir facies and the diagenetic evolution sequence. The research indicated that this reservoir bed can be divided into five types of diagenetic reservoir facies, namely strong dissolution, chlorite-lined intergranular pores, compaction and pressure solution, carbonate cementation and secondary quartz increase. There are, however, just two diagenetic reservoir facies which provide low-permeability reservoir beds, namely strong dissolution and chlorite-lined intergranular pores. We also analyzed their diagenetic evolution sequences and the origin of the low-permeability reservoir bed. Besides, it was also indicated that the composition and structure of sandstones, types of sedimentary microfacies, diagenesis history as well as the tectonic reworking in later periods are the main factors controlling the formation of the low-permeability reservoir bed. The above- mentioned factors establish the foundation for the forecasting the distribution of high quality reservoir beds.
文摘According to the geological characteristics and their influential factors of the low-permeability reservoirs, a comprehensive method for evaluation of low-permeability reservoirs is put forward. The method takes a matrix system as the basis, a fracture system as the focus and a stress field system as the restricted factor. It can objectively reflect not only the storage capability and seepage capability of low-permeability reservoirs, but also the effect on development as well. At the same time, it can predict the seepage characteristics at different development stages and provide a reasonable geological basis for the development of low-permeability reservoirs.
基金the Committee of the National HighTechnology Research and Development Program of China(863 Program) for providing financial support for thisresearch project (Project No.2006AA06A109)the support provided by the Changjiang Scholarsand Innovative Research Team(No.IRT0411),Ministry ofEducation,China.
文摘This paper discusses the systematic design and development of low-damage drilling fluid to protect the low-permeability gas reservoir of the Sulige block in the Ordos Basin, Inner Mongolia Autonomous Region, China. Based on investigation of the geological characteristics and the potential formation damage of the Permian formation of the reservoir, waterblocking due to invasion of drilling or completion fluids was identified one of the most severe causes of damage to gas well deliverability. By adopting the phase trap prevention method, ideal packing theory, and film-forming technology, a lowdamage drilling fluid, sodium formate brine containing efficient waterblocking preventing surfactants, optimized temporary bridging agents （TBAs）, and film-forming agents has been developed. The performance of the new drilling fluid was evaluated by using a variety of techniques. The results show that the fluid has good rheological properties, good strong shale-swelling inhibition, good temporary plugging effect, ultra-low filtration, and good lubricity. It can efficiently minimize waterblocking and can be used to drill horizontal wells with minimal intervention of the reservoir in the Sulige Gas Field.
基金the financial support from the National Natural Science Foundation of China (Nos. 52074249, 51874261, 52304011)。
文摘The intensive development of tight reservoirs has positioned them as a strategic alternative to conventional oil and gas resources. Existing enhanced oil recovery(EOR) methods struggle to effectively exploring reservoir oil, resulting in low recovery rates. Novel and effective means of developing tight reservoirs are urgently needed. Nanomaterials have shown promising applications in improving water flooding efficiency, with in-depth research into mechanisms that lower injection pressure and increase water injection volumes. However, the extent of improvement remains limited. In this study, a silicon quantum dots(Si-QDs) material was synthesized via a hydrothermal synthesis method and used to prepare a nanofluid for the efficient recovery of tight reservoir. The Si-QDs, with an approximate diameter of 3 nm and a spherical structure, were surface functionalized with benzenesulfonic acid groups to enhance the performance. The developed nanofluid demonstrated stability without aggregation at 120℃ and a salinity of 60000 mg/L. Core flooding experiments have demonstrated the attractive EOR capabilities of Si-QDs, shedding light of the EOR mechanisms. Si-QDs effectively improve the wettability of rocks, enhancing the sweeping coefficient of injected fluids and expanding sweeping area.Within this sweeping region, Si-QDs efficiently stripping adsorbed oil from the matrix, thus increasing sweeping efficiency. Furthermore, Si-QDs could modify the state of pore-confined crude oil, breaking it down into smaller particles that are easier to displacement in subsequent stages. Si-QDs exhibit compelling EOR potential, positioning them as a promising approach for effectively developing tight oil reservoirs.
基金The authors gratefully acknowledge the financial supports from the National Science Foundation of China under Grant 52274027 as well as the High-end Foreign Experts Recruitment Plan of the Ministry of Science and Technology China under Grant G2022105027L.
文摘Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.
基金support of the National Natural Science Foundation of China(No.52120105007)the National Key Research and Development Program of China(2019Y FA0708700)are gratefully acknowledged.
文摘Polymerflooding is an effective method widely applied for enhancing oil recovery(EOR)by reducing the mobility ratio between theinjected water and crude oil.However,traditional polymers encounter challenges in high salinity reservoirs due to their salt sensitivity.Toovercome this challenge,we synthesized a zwitterion polymer(PAMNS)with salt-induced tackifying property through copolymerization ofacrylamide and a zwitterion monomer,methylacrylamide propyl-N,N-dimethylbutylsulfonate(NS).NS monomer is obtained from thereaction between 1,4-butanesultone and dimethylamino propyl methylacrylamide.In this study,the rheological properties,salt responsiveness,and EOR efficiency of PAMNS were evaluated.Results demonstrate that PAMNS exhibits desirable salt-induced tackifyingcharacteristics,with viscosity increasing up to 2.4 times as the NaCl concentration reaches a salinity of 30×10^(4)mg L^(-1).Furthermore,highvalence ions possess a much stronger effect on enhancing viscosity,manifested as Mg^(2+)>Ca^(2+)>Na^(+).Molecular dynamics simulations(MD)andfluid dynamics experiment results demonstrate that PAMNS molecules exhibit a more stretched state and enhanced intermolecularassociations in high-salinity environments.It is because of the salt-induced tackifying,PAMNS demonstrates superior performance inpolymerflooding experiments under salinity ranges from 5×10^(4)mg L^(-1)to 20×10^(4)mg L^(-1),leading to 10.38–19.83%higher EOR thantraditional polymers.
基金The authors sincerely appreciate the financial support from the National Natural Science Foundation of China(No.52074279,51874261).
文摘Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.
基金funded by Science Foundation of China University of Petroleum, Beijing (No. 2462021YXZZ009)The Strategic Cooperation Technology Projects of CNPC and CUPB (No. ZLZX 2020-01)Innovation Capability Support of Shaanxi (Program No. 2023-CX-TD-31) Technical Innovation Team for Low Carbon Environmental Protection and Enhanced Oil Recovery in Unconventional Reservoirs。
文摘Supercritical CO_(2)(SC-CO_(2)) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO_(2) hybrid fracturing method has been proposed, which combines the advantages of SC-CO_(2) fracturing and hydraulic fracturing. However, the specific impacts of different pre-SC-CO_(2) injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO_(2) injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO_(2) injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO_(2) leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO_(2) injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO_(2) is positively correlated with the injection displacement and volume.Additionally, pre-injection of SC-CO_(2) enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO_(2) injection parameters.Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO_(2) hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO_(2) injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of pre SC-CO_(2) hybrid fracturing in shale oil reservoirs.
文摘Countercurrent imbibition is an important mechanism for tight oil recovery,that is,water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture.Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces.We used the computed tomography(CT)scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance(CID)at different fluid pressures,initial water saturations,and permeability.Surprisingly,experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule(i.e.,evolutes proportional to square root of time,t^(0.5)).At early stage,CID extends faster than t^(0.5)(super-diffusive);while at late stage,CID extends much slower than t^(0.5)(sub-diffusive).After tens of hours,the CID change becomes too slow to be practically efficient for tight oil recovery.This research demonstrates that this deviation from classic theory is a result of(1)a much longer characteristic capillary length than effective invasion depth,which eliminates full development of a classical displacement front;and(2)non-zero flow at low water saturation,which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks.To well depict the details of the imbibition front in this situation,we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations,which successfully rationalizes the non-diffusive behavior and fits experimental data.Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition,beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery(EOR)strategy than soaking for longer time.
基金supported by the National Natural Science Foundation of China(No.52174038 and No.52004307)China Petroleum Science and Technology Project-Major Project-Research on Tight Oil-Shale Oil Reservoir Engineering Methods and Key Technologies in Ordos Basin(No.ZLZX2020-02-04)Science Foundation of China University of Petroleum,Beijing(No.2462018YJRC015)。
文摘Under the policy background and advocacy of carbon capture,utilization,and storage(CCUS),CO_(2)-EOR has become a promising direction in the shale oil reservoir industry.The multi-scale pore structure distribution and fracture structure lead to complex multiphase flow,comprehensively considering multiple mechanisms is crucial for development and CO_(2) storage in fractured shale reservoirs.In this paper,a multi-mechanism coupled model is developed by MATLAB.Compared to the traditional Eclipse300 and MATLAB Reservoir Simulation Toolbox(MRST),this model considers the impact of pore structure on fluid phase behavior by the modified Peng—Robinson equation of state(PR-EOS),and the effect simultaneously radiate to Maxwell—Stefan(M—S)diffusion,stress sensitivity,the nano-confinement(NC)effect.Moreover,a modified embedded discrete fracture model(EDFM)is used to model the complex fractures,which optimizes connection types and half-transmissibility calculation approaches between non-neighboring connections(NNCs).The full implicit equation adopts the finite volume method(FVM)and Newton—Raphson iteration for discretization and solution.The model verification with the Eclipse300 and MRST is satisfactory.The results show that the interaction between the mechanisms significantly affects the production performance and storage characteristics.The effect of molecular diffusion may be overestimated in oil-dominated(liquid-dominated)shale reservoirs.The well spacing and injection gas rate are the most crucial factors affecting the production by sensitivity analysis.Moreover,the potential gas invasion risk is mentioned.This model provides a reliable theoretical basis for CO_(2)-EOR and sequestration in shale oil reservoirs.
基金Supported by the PetroChina Science and Technology Major Project(2016E0201)。
文摘Based on the geochemical,seismic,logging and drilling data,the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics,the tight oil enrichment model and its major controlling factors.First,the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation,with the development of nose structure around sag and the broad and continuous distribution of sand bodies.The reservoirs are tight on the whole.Second,the configuration of multiple elements,such as high-quality source rocks,reservoir rocks,fault,overpressure and structure,controls the tight oil enrichment in the Fuyu reservoirs.The source-reservoir combination controls the tight oil distribution pattern.The pressure difference between source and reservoir drives the charging of tight oil.The fault-sandbody transport system determines the migration and accumulation of oil and gas.The positive structure is the favorable place for tight oil enrichment,and the fault-horst zone is the key part of syncline area for tight oil exploration.Third,based on the source-reservoir relationship,transport mode,accumulation dynamics and other elements,three tight oil enrichment models are recognized in the Fuyu reservoirs:(1)vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks,that is,driven by overpressure,hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks;(2)transport of hydrocarbon through faults between separated source and reservoirs,that is,driven by overpressure,hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks;and(3)migration of hydrocarbon through faults and sandbodies between separated source and reservoirs,that is,driven by overpressure,hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks,and then migrates laterally through sandbodies.Fourth,the differences in oil source conditions,charging drive,fault distribution,sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs.Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Sag has good conditions for tight oil enrichment and has been less explored,and it is an important new zone for tight oil exploration in the future.
