Accurately predicting relative permeability is an important issue in the research of multiphase flow in tight reservoirs.Existing predictive models typically rely on the capillary tube bundle model featuring circular ...Accurately predicting relative permeability is an important issue in the research of multiphase flow in tight reservoirs.Existing predictive models typically rely on the capillary tube bundle model featuring circular cross-sections,often overlooking the impact of pore geometry on fluid flow behavior within reservoirs.In this work,the intermingled fractal theory of porous media is introduced to characterize the intricate local features within the internal space of tight rocks.Initially,iterative rules for diverse fractal units are skillfully designed to capture the actual characteristics of pore cross-sectional shapes.Subsequently,analytical relationships are derived between the iterative parameters and the area,wetted perimeter,and hydraulic diameter of pores generated by these units,followed by the establishment of a relative permeability model that considers pore geometry.The model's validity is confirmed through comparisons with experimental data and published relative permeability models,with correlation coefficients exceeding 0.996.Finally,various factors affecting two-phase flow characteristics are analyzed.The results reveal that pore geometry has a significant impact on flow behavior in porous media.Assuming that the flow channels are cylindrical typically leads to an overestimation of permeability,with the maximum relative error reaching 46.91%.Additionally,the tortuosity fractal dimension is a determinant factor influencing the relative permeability of both wetting and nonwetting fluids,and the phase permeability is sensitive to variations in solid particle size and porosity.The proposed intermingled fractal model enhances the accuracy of evaluating fluid flow characteristics in microscale pore channels and offers a novel framework for simulating porous media with complex geometries.展开更多
In this study,we developed a high-resolution stratigraphic framework for the Yanchang Formation in the Huachi Block of the Qingyang Oilfield,located in the Ordos Basin,northwest China.Using well log and seismic data,w...In this study,we developed a high-resolution stratigraphic framework for the Yanchang Formation in the Huachi Block of the Qingyang Oilfield,located in the Ordos Basin,northwest China.Using well log and seismic data,we traced and correlated sweet-spot sand bodies in tight oil reservoirs.Three long-term base-level cycles were identified in the Yanchang Formation,and five medium-term base-level cycles were delineated from the Chang 72 sub-Member to the Chang 4+5 Members,corresponding to five distinct oil groups.The primary production layer,Oil Group 3,was further divided into short-term and very short-term base-level cycles to facilitate the prediction of hydrocarbon target zones.Sweet-spot sand bodies were traced and correlated within very short-term cycles.The sweet-spot sand bodies are mainly sublacustrine channel deposits in the delta front,which were mainly developed in the five single layers(3-1-2,3-1-3,3-1-4,3-2-2,3-2-3 and 3-2-5)of the small layers 3-1 and 3-2 during the regression periods of base-level cycles.The sweet spot sand bodies within the small layer 3-2 are derived from three sets of sources in the northeast,northwest,and south of the basin.The Class I sweet spot is distributed within the single layer 3-2-5,with an average thickness of about 6 m,covering about 25%of the study area.The Class II sweet spot is developed in all five single layers,with the thickest and largest sweet-spot sand body in the Single layer 3-2-3,covering about 90%of the study area.This study highlights the critical importance of establishing a high-resolution sequence stratigraphic framework for the refined delineation of sweet-spot sand bodies within a deltaic-lacustrine depositional system.Additionally,sublacustrine fan deposits formed during the regressive semi-cycle were identified as key sweet spots in the study area.展开更多
Tight oil reservoirs face significant challenges,including rapid production decline,low recovery rates,and a lack of effective energy replenishment methods.In this study,a novel development model is proposed,based on ...Tight oil reservoirs face significant challenges,including rapid production decline,low recovery rates,and a lack of effective energy replenishment methods.In this study,a novel development model is proposed,based on inter-fracture injection following volumetric fracturing and relying on a high-temperature and high-pressure large-scale physical simulation system.Additionally,the CMG(Computer Modelling Group Ltd.,Calgary City,Canada)software is also used to elucidate the impact of various single factors on the production of horizontal wells while filtering out the interference of others.The effects of fracture spacing,fracture half-length,and the injection-production ratio are studied.Results indicate that under rejection pressures of 6.89,3.45,and 1.88 MPa,the times to establish stable flow are 50,193,and 395 min,respectively.Higher injection pressures lead to an increased oil recovery efficiency,with the highest observed efficiency at 16.93%.This indicates that,compared with conventional medium and high permeability reservoirs,tight oil reservoirs exhibit similar pore throats and larger capillary forces when oil and water flow in both phases.Higher pressures reduce capillary forces,displacing more oil droplets,thus enhancing oil recovery efficiency.Moreover,under inter-fracture displacement conditions,the pressure gradient at both the injection and production ends remain consistent,with minimal pressure loss near the wellbore.This feature ensures that the crude oil in the middle of the reservoir also possesses displacement energy,thereby enhancing overall crude oil displacement efficiency.展开更多
The Upper Triassic oil accumulations in the Ordos Basin is the most successful tight oil play in China,with average porosity values of less than 10% and permeability values below 1.0 mD.This study investigated the geo...The Upper Triassic oil accumulations in the Ordos Basin is the most successful tight oil play in China,with average porosity values of less than 10% and permeability values below 1.0 mD.This study investigated the geological characteristics and origin of the tight oil accumulations in the Chang 6 member of the Upper Triassic Yanchang Formation in the Shanbei area based on over 50,000 petrological,source-rock analysis,well logging and production data.The tight oil accumulation of the Chang 6 member is distributed continuously in the basin slope and the centre of the basin.The oilwater relationships are complex.Laumontite dissolution pores are the most important storage spaces,constituting 30%-60% of total porosity and showing a strong positive relationship with oil production.The pore-throat diameter is less than 1 μm,and the calculated critical height of the oil column is much larger than the tight sand thickness,suggesting that the buoyancy was probably of limited importance for oil migration.The pressure difference between the source rocks and sandstone reservoirs is inferred to have provided driving force for hydrocarbon migration.Two factors of source-reservoir configuration and laumontite dissolution contributed to the formation of the Chang 6 tight oil accumulations.Intense hydrocarbon generation and continuous sand bodies close to the hydrocarbon kitchen are the foundation for the large-scale oil distribution.Dissolution of feldspar-laumontite during the process of organic matter evolution generated abundant secondary pores and improved the reservoir quality.展开更多
Tight oil has become the focus in exploration and development of unconventional oil in the world, especially in North America and China. In North America, there has been intensive exploration for tight oil in marine. ...Tight oil has become the focus in exploration and development of unconventional oil in the world, especially in North America and China. In North America, there has been intensive exploration for tight oil in marine. In China, commercial exploration for tight oil in conti- nental sediments is now steadily underway. With the dis- covery of China＇s first tight oil field--Xin＇anbian Oilfield in the Ordos Basin, tight oil has been integrated officially into the category for reserves evaluation. Geologically, tight oil is characterized by distribution in depressions and slopes of basins, extensive, mature, and high-quality source rocks, large-scale reservoir space with micro- and nanopore throat systems, source rocks and reservoirs in close contact and with continuous distribution, and local ＂sweet area.＂ The evaluation of the distribution of tight oil ＂sweet area＂ should focus on relationships between ＂six features.＂ These are source properties, lithology, physical properties, brittleness, hydrocarbon potential, and stress anisotropy. In North America, tight oil prospects are distributed in lamellar shale or marl, where natural fractures are fre- quently present, with TOC 〉 4 %, porosity 〉 7 %, brittle mineral content 〉 50 %, oil saturation of 50 %-80 %, API 〉 35~, and pressure coefficient 〉 1.30. In China, tight oil prospects are distributed in lamellar shale, tight sand- stone, or tight carbonate rocks, with TOC 〉 2 %, poros- ity 〉 8 %, brittle mineral content 〉 40 %, oil saturation of 60 %-90 %, low crude oil viscosity, or high formation pressure. Continental tight oil is pervasive in China and its preliminary estimated technically recoverable resources are about （20-25） × lO8^ t.展开更多
Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the develo...Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the development efficiency of block matrix, surfactant-aided imbibition is a potential way. The current work aimed to explain comprehensively how surfactants can enhance the imbibition rate. Laboratory experiments were performed to investigate the effects of wettability, interfacial tension(IFT), and relative permeability as the key parameters underlying surfactant solution imbibition. Two different types of surfactants, sodium dodecyl sulfate and polyethylene glycol octylphenol ether, at varied concentrations were tested on reservoir rocks. Experimental results showed that the oil recovery rate increased with increased wettability alteration and IFT and decreased residual oil saturation. A mechanistic simulator developed in previous studies was used to perform parametric analysis after successful laboratory-scale validation. Results were proven by parametric studies. This study,which examined the mechanism and factors influencing surfactant solution imbibition, can improve understanding of surfactant-aided imbibition and surfactant screening.展开更多
In exploration for tight oil, the content and saturation of hydrocarbon in the tight reservoir is a key factor for evaluating the reserve. Therefore, it is necessary to study the geological history of hydrocarbon accu...In exploration for tight oil, the content and saturation of hydrocarbon in the tight reservoir is a key factor for evaluating the reserve. Therefore, it is necessary to study the geological history of hydrocarbon accumulation and the tight oil charging process. However, kinetic models used for petroleum development are not applicable for petroleum exploration. In this study, a static resistance model[ is proposed after analyzing resistances in ultra-slow flow in porous media. Using this model, the disco^atinuous pattern of oil charging is reproduced through incompressible Navier-Stokes equations, the phase field method and the finite element method. This study also explains macroscopic percolation behavior with microscopic flow mechanisms and discusses some issues in ultra-slow flow in a micro/nano pore-throat network. The resistance analysis reveals that capillary resistance and dissipation resistance are dominant factors in the mechanism of oil accumulation in tight reservoirs. Numerical simulations show that pressure thresholds exist and result in discontinuous oil charging. Generally, it is proven that the static model is more applicable than kinetic models in describing oil accumulation in tight reservoirs.展开更多
Volumetric fracturing is a primary stimulation technology for economical and effective exploitation of tight oil reservoirs. The main mechanism is to connect natural fractures to generate a fracture network system whi...Volumetric fracturing is a primary stimulation technology for economical and effective exploitation of tight oil reservoirs. The main mechanism is to connect natural fractures to generate a fracture network system which can enhance the stimulated reservoir volume. By using the combined finite and discrete element method, a model was built to describe hydraulic fracture propagation in tight oil reservoirs. Considering the effect of horizontal stress difference, number and spacing of perforation clus- ters, injection rate, and the density of natural fractures on fracture propagation, we used this model to simulate the fracture propagation in a tight formation of a certain oil- field. Simulation results show that when the horizontal stress difference is lower than 5 MPa, it is beneficial to form a complex fracture network system. If the horizontal stress difference is higher than 6 MPa, it is easy to form a planar fracture system; with high horizontal stress differ- ence, increasing the number of perforation clusters is beneficial to open and connect more natural fractures, and to improve the complexity of fracture network and the stimulated reservoir volume （SRV）. As the injection rate increases, the effect of volumetric fracturing may be improved; the density of natural fractures may only have a great influence on the effect of volume stimulation in a low horizontal stress difference.展开更多
Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs,especially in the US.However,the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery f...Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs,especially in the US.However,the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery factor.Therefore,the application of EOR in the early reservoir development phase is considered effective for fast-paced and economical tight oil recovery.To achieve these objectives,it is imperative to determine the optimum EOR potential and the best-suited EOR application for every individual tight oil reservoir to maximize its ultimate recovery factor.Since most of the tight oil reservoirs are found in wide spatial source rock with complex and compacted pores and poor geophysical properties yet they hold high saturation of good quality oil and therefore,every single percent increase in oil recovery from such huge reservoirs potentially provide an additional million barrels of oil.Hence,the EOR application in such reservoirs is quite essential.However,the physical understanding of EOR applications in different circumstances from laboratory to field scale is the key to success and similarly,the fundamental physical concepts of fluid flow-dynamics under confinement conditions play an important role.This paper presents a detailed discussion on laboratory-based experimental achievements at micro-scale including fundamental concepts under confinement environment,physics-based numerical studies,and recent actual field piloting experiences based on the U.S.unconventional plays.The objective of this paper is to discuss all the critical reservoir rock and fluid properties and their contribution to reservoir development through massive multi-staged hydraulic fracture networks and the EOR applications.Especially the CO_(2)and produced hydrocarbon gas injection through single well-based huff-n-puff operational constraints are discussed in detail both at micro and macro scale.展开更多
Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water dis...Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water distribution in rocks during imbibition using various nanofluids was less discussed in previous studies.In this study,we systematically examined the imbibition efficiencies of various nanofluids at60℃.Furthermore,the migration of nanofluids and oil distribution in the rock pores were monitored using nuclear magnetic resonance(NMR).The nanofluids were prepared by dispersing silica nanoparticles and five different types of surfactants i.e.,anionic-nonionic,anionic,nonionic,amphoteric and cationic surfactants in deionized(DI)water.Subsequently,interfacial tension(IFT)and contact angle measurements were conducted to reveal the underlying EOR mechanisms of various nanofluids.The experimental results showed that the EOR potential of the different types of nanofluids was in the order anionic-nonionic>anionic>nonionic>amphoteric>cationic>brine.Anionic-nonionic(sodium lauryl ether sulfate(SLES))and anionic(sodium dodecyl sulfonate(SDS))nanofluids exhibited excellent capability of wettability alteration,and increased oil recovery by 27.96%and 23.08%,respectively,compared to brine.The NMR results also showed that mesopores(0.1-1μm)were the dominant developed pores in the rocks,and contributed the most to imbibition efficiency.In addition,the imbibition of nanofluids initially took place in mesopores and micropores before moving into macropores.This study provides fundamental information on the selection of nanofluids for EOR in tight oil reservoirs.The study also improved the understanding of oil/water distribution during the imbibition of the proposed nanofluids.展开更多
The selection of refracturing candidate is one of the most important jobs faced by oilfield engineers. However, due to the complicated multi-parameter relationships and their comprehensive influence, the selection of ...The selection of refracturing candidate is one of the most important jobs faced by oilfield engineers. However, due to the complicated multi-parameter relationships and their comprehensive influence, the selection of refracturing candidate is often very difficult. In this paper, a novel approach combining data analysis techniques and fuzzy clustering was proposed to select refracturing candidate. First, the analysis techniques were used to quantitatively calculate the weight coefficient and determine the key factors. Then, the idealized refracturing well was established by considering the main factors. Fuzzy clustering was applied to evaluate refracturing potential. Finally, reservoirs numerical simulation was used to further evaluate reservoirs energy and material basis of the optimum refracturing candidates. The hybrid method has been successfully applied to a tight oil reservoir in China. The average steady production was 15.8 t/d after refracturing treatment, increasing significantly compared with previous status. The research results can guide the development of tight oil and gas reservoirs effectively.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
A mathematical model, fully coupling multiple porous media deformation and fluid flow, was established based on the elastic theory of porous media and fluid-solid coupling mechanism in tight oil reservoirs. The finite...A mathematical model, fully coupling multiple porous media deformation and fluid flow, was established based on the elastic theory of porous media and fluid-solid coupling mechanism in tight oil reservoirs. The finite element method was used to determine the numerical solution and the accuracy of the model was verified. On this basis, the model was used to simulate productivity of multistage fractured horizontal wells in tight oil reservoirs. The results show that during the production of tight oil wells, the reservoir region close to artificial fractures deteriorated in physical properties significantly, e.g. the aperture and conductivity of artificial fractures dropped by 52.12% and 89.02% respectively. The simulations of 3000-day production of a horizontal well in tight oil reservoir showed that the predicted productivity by the uncoupled model had an error of 38.30% from that by the fully-coupled model. Apparently, ignoring the influence of fluid-solid interaction effect led to serious deviations of the productivity prediction results. The productivity of horizontal well in tight oil reservoir was most sensitive to the start-up pressure gradient, and second most sensitive to the opening of artificial fractures. Enhancing the initial conductivity of artificial fractures was helpful to improve the productivity of tight oil wells. The influence of conductivity, spacing, number and length of artificial fractures should be considered comprehensively in fracturing design. Increasing the number of artificial fractures unilaterally could not achieve the expected increase in production.展开更多
Taking the tight oil of the Zhongnan sag in the Ordos Basin,Jimusar sag in the Junggar Basin and Qingxi sag in the Jiuquan Basin as study objects,based on field survey,dissection of tight oil reservoirs,sample test,mo...Taking the tight oil of the Zhongnan sag in the Ordos Basin,Jimusar sag in the Junggar Basin and Qingxi sag in the Jiuquan Basin as study objects,based on field survey,dissection of tight oil reservoirs,sample test,modeling experiment and comprehensive analysis,this study reveals that the tight oil accumulates at start-up pressure,advances under differential pressure,diffuses at alternating fast and low speeds,charges in stepped large area and migrates rapidly through fractures,and enriches in dominant fractures and pores.The root cause of ladder-like charge is the multiple scales of pores.The widespread source rock with high hydrocarbon generation intensity is the material basis for tight oil enrichment;the dominant source reservoir assemblage is the basic unit for tight oil enrichment;fractures and beddings are conducive to local rapid migration of tight oil;fractures and pores work together to control the enrichment of tight oil.Two typical accumulation models of tight oil are established,namely"source reservoir in coexistence,four optimal factors controlling enrichment around central area,and large-scale continuous distribution"for a large freshwater lake clastic rock basin and"source reservoir integration,four optimal factors controlling enrichment,central area distribution,small in size but high in enrichment degree"for a small saline lake diamictite depression.展开更多
Xin’anbian Oilfield of the Ordos Basin is the large tight oilfield to be first exploration discovery in china.The production of tight oil increased significantly in recent years.It shows great exploration potential o...Xin’anbian Oilfield of the Ordos Basin is the large tight oilfield to be first exploration discovery in china.The production of tight oil increased significantly in recent years.It shows great exploration potential of Chang 7 tight oil.But the physical property and hydrocarbon enrichment characteristics of Chang 7 tight oil reservoirs were rarely studied,The forming conditions of tight oil reservoirs are systematically summarized and analyzed through the study of hydrocarbon generation,sedimentary reservoirs and hydrocarbon migration and accumulation based on production and core experimental data.The result shows that,The porosity of the Chang 7_(2)reservoir mainly distributed in 5.0-11.0%,average at 7.9%,The permeability mainly distributed in 0.04-0.18×10^(-3)μm^(2),average at 0.12×10^(-3)μm^(2),The pore diameters of the tight oil reservoir distributed in 2-8μm.The high-quality Chang 7_(3)source rocks and the micropsammite of Chang 7_(2)subaqueous distributary channel were widely distributed in the study area.The lenticular or banded sand bodies are distributed among mudstone or hydrocarbon source rocks and have the advantage of migration distance for hydrocarbon accumulation.The reservoir space is composed of micro-nanometer pores and throat,that is formed in the process of increasing pressure during hydrocarbon generation and hydrocarbon accumulation.The Chang 7 tight oil was generated in the early Cretaceous and injected into the sand of the subaqueous distributary channel driven by continuous hydrocarbon generation supercharging.The formation and accumulation of tight oil reservoirs are mainly controlled by source rocks,sedimentary microfacies and reservoirs of good quality.展开更多
This study aimed to investigate the complete distribution of reservoir space in tight oil sandstone combining casting slices, field emission scanning electron microscopy(FE-SEM), the pore-throat theory model, high-res...This study aimed to investigate the complete distribution of reservoir space in tight oil sandstone combining casting slices, field emission scanning electron microscopy(FE-SEM), the pore-throat theory model, high-resolution image processing, mathematical statistics, and other technical means. Results of reservoir samples from the Xin’anbian area of Ordos Basin showed that the total pore radius curve of the tight oil sandstone reservoir exhibited a multi-peak distribution, and the peaks appeared to be more focused on the ends of the range. This proved that pores with a radius of 1–50,000 nm provided the most significant storage space for tight oil, indicating that special attention should be paid to this range of the pore size distribution. Meanwhile, the complete throat radius curve of the tight oil sandstone reservoir exhibited a multipeak distribution. However, the peak values were distributed throughout the scales. This confirmed that the throat radius in the tight oil sandstone reservoir was not only in the range of hundreds of nanometers but was also widely distributed in the scale approximately equal to the pore size. The new rapid determination method could provide a precise theoretical basis for the comprehensive evaluation, exploration, and development of a tight oil sandstone reservoir.展开更多
Nitrogen huff-n-puff(N_(2)HnP) appears to be an economical and high-efficiency enhanced oil recovery(EOR) technique for tight oil reservoirs.There is however a lack of understanding of the pore-level EOR performance o...Nitrogen huff-n-puff(N_(2)HnP) appears to be an economical and high-efficiency enhanced oil recovery(EOR) technique for tight oil reservoirs.There is however a lack of understanding of the pore-level EOR performance of N2HnP under tight reservoir conditions.In this work,a non-magnetic reactor was created and combined with a nuclear magnetic resonance(NMR) device for real-time monitoring of oil distribution in the HnP experiment.N_(2)HnP experiments were then performed in a tight sandstone core sample at a temperature of 353 K and an injection pressure≥ 24 MPa.The pore-level oil distribution under reservoir conditions was monitored and the EOR performance of N2HnP in specific pores was analyzed.The pore throat structures of the core sample and the phase behavior of the N_(2)-Oil system were analyzed to elucidate the EOR mechanism of N_(2)HnP.An oil recovery factor of 37.52% can be achieved after four cycles,which proves the EOR potential of N_(2)HnP for tight reservoirs.The highest recoveries after N_(2)HnP are obtained in the large pores,followed by the medium pores,the small pores,and finally the micro pores.Increases in soaking time and injection pressure resulted in slight and pronounced increases in oil recovery,respectively,both of which are mainly reflected in the first cycle.Specifically,increasing the soaking time only slightly improves the cumulative oil recovery in the small pores while increasing the injection pressure significantly improves the cumulative oil recovery in the small,medium,and large pores simultaneously.However,variations in both injection pressure and soaking time have a negligible effect on the cumulative oil recovery of the micro pores.展开更多
CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and i...CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO_(2)huff and puff and the contribution of sweeping mode to recovery.The experimental results show that the development process of CO_(2)huff and puff can be divided into four stages,namely,CO_(2)backflow,production of gas with some oil,high-speed oil production,and oil production rate decline stages.The production of gas with some oil stage is dominated by free gas displacement,and the high-speed oil production stage is dominated by dissolved gas displacement.CO_(2)injection volume and development speed are the major factors affecting the oil recovery.The larger the injected CO_(2)volume and the lower the development speed,the higher the oil recovery will be.The reasonable CO_(2)injection volume and development speed should be worked out according to oilfield demand and economic evaluation.There is a reasonable soaking time in CO_(2)huff and puff.Longer soaking time than the optimum time makes little contribution to oil recovery.In field applications,the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period.The oil recovery of CO_(2)huff and puff mainly comes from the contribution of flow sweep and diffusion sweep,and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.展开更多
Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China,such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin,NE China sandy conglomerate o...Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China,such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin,NE China sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin,NE China the theoretical lower limit,oil accumulation lower limit,effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method,oil bearing occurrence method,oil testing productivity method and mechanical balance method,respectively.Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs,determine the grading criterion of tight reservoirs,and analyze its correlation with the limit of reservoir formation.The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties,the boundary of classⅡand classⅢtight reservoirs corresponds to the lower limit of effective flow,the boundary of classⅢand classⅣtight reservoirs corresponds to the lower limit of reservoir forming,and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir.Finally,the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir,and classⅠand classⅡtight reservoirs are the favorable sections for high production of tight oil.展开更多
The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies,such as low recovery efficiency,rapid production decline,high cost,and complexity,etc.Therefore,...The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies,such as low recovery efficiency,rapid production decline,high cost,and complexity,etc.Therefore,a new technology,the so-called fracturing-oil expulsion integration,which does not need flowback after fracturing while making full use of the fracturing energy and gel breaking fluids,are needed to enable efficient exploitation of tight oil.A novel triple-responsive smart fluid based on“pseudo-Gemini”zwitterionic viscoelastic surfactant(VES)consisting of N-erucylamidopropyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate(EHSB),N,N,N′,N′-tetramethyl-1,3-propanediamine(TMEDA)and sodium p-toluenesulfonate(NaPts),is developed.Then,the rheology of smart fluid is systematically studied at varying conditions(CO_(2),temperature and pressure).Moreover,the mechanism of triple-response is discussed in detail.Finally,a series of fracturing and spontaneous imbibition performances are systematically investigated.The smart fluid shows excellent CO_(2)-,thermal-,and pressure-triple responsive behavior.It can meet the technical requirement of tight oil fracturing construction at 140°C in the presence of 3.5 MPa CO_(2).The gel breaking fluid shows excellent spontaneous imbibition oil expulsion(∼40%),salt resistance(1.2×104 mg/L Na+),temperature resistance(140°C)and aging stability(30 days).展开更多
基金financially supported by the Hebei Provincial Natural Science Foundation of China(No.D2023402012)the Major Science and Technology Project of China National Petroleum Corporation(No.2024DJ87)。
文摘Accurately predicting relative permeability is an important issue in the research of multiphase flow in tight reservoirs.Existing predictive models typically rely on the capillary tube bundle model featuring circular cross-sections,often overlooking the impact of pore geometry on fluid flow behavior within reservoirs.In this work,the intermingled fractal theory of porous media is introduced to characterize the intricate local features within the internal space of tight rocks.Initially,iterative rules for diverse fractal units are skillfully designed to capture the actual characteristics of pore cross-sectional shapes.Subsequently,analytical relationships are derived between the iterative parameters and the area,wetted perimeter,and hydraulic diameter of pores generated by these units,followed by the establishment of a relative permeability model that considers pore geometry.The model's validity is confirmed through comparisons with experimental data and published relative permeability models,with correlation coefficients exceeding 0.996.Finally,various factors affecting two-phase flow characteristics are analyzed.The results reveal that pore geometry has a significant impact on flow behavior in porous media.Assuming that the flow channels are cylindrical typically leads to an overestimation of permeability,with the maximum relative error reaching 46.91%.Additionally,the tortuosity fractal dimension is a determinant factor influencing the relative permeability of both wetting and nonwetting fluids,and the phase permeability is sensitive to variations in solid particle size and porosity.The proposed intermingled fractal model enhances the accuracy of evaluating fluid flow characteristics in microscale pore channels and offers a novel framework for simulating porous media with complex geometries.
基金supported by the National Key Research and DevelopmentProgram of China(Grant No.2023YFF0804300 and 2023YFF0804303).
文摘In this study,we developed a high-resolution stratigraphic framework for the Yanchang Formation in the Huachi Block of the Qingyang Oilfield,located in the Ordos Basin,northwest China.Using well log and seismic data,we traced and correlated sweet-spot sand bodies in tight oil reservoirs.Three long-term base-level cycles were identified in the Yanchang Formation,and five medium-term base-level cycles were delineated from the Chang 72 sub-Member to the Chang 4+5 Members,corresponding to five distinct oil groups.The primary production layer,Oil Group 3,was further divided into short-term and very short-term base-level cycles to facilitate the prediction of hydrocarbon target zones.Sweet-spot sand bodies were traced and correlated within very short-term cycles.The sweet-spot sand bodies are mainly sublacustrine channel deposits in the delta front,which were mainly developed in the five single layers(3-1-2,3-1-3,3-1-4,3-2-2,3-2-3 and 3-2-5)of the small layers 3-1 and 3-2 during the regression periods of base-level cycles.The sweet spot sand bodies within the small layer 3-2 are derived from three sets of sources in the northeast,northwest,and south of the basin.The Class I sweet spot is distributed within the single layer 3-2-5,with an average thickness of about 6 m,covering about 25%of the study area.The Class II sweet spot is developed in all five single layers,with the thickest and largest sweet-spot sand body in the Single layer 3-2-3,covering about 90%of the study area.This study highlights the critical importance of establishing a high-resolution sequence stratigraphic framework for the refined delineation of sweet-spot sand bodies within a deltaic-lacustrine depositional system.Additionally,sublacustrine fan deposits formed during the regressive semi-cycle were identified as key sweet spots in the study area.
基金supported by the Study on the Seepage Law of Typical Low-Grade Oil Reservoirs,New Methods for Enhancing Oil Recovery(2021DJ1102)the National Science and Technology Major Special Support Program(Grant No.2017ZX05064)the CNPC Innovation Foundation(Grant No.2022DQ02-0604).
文摘Tight oil reservoirs face significant challenges,including rapid production decline,low recovery rates,and a lack of effective energy replenishment methods.In this study,a novel development model is proposed,based on inter-fracture injection following volumetric fracturing and relying on a high-temperature and high-pressure large-scale physical simulation system.Additionally,the CMG(Computer Modelling Group Ltd.,Calgary City,Canada)software is also used to elucidate the impact of various single factors on the production of horizontal wells while filtering out the interference of others.The effects of fracture spacing,fracture half-length,and the injection-production ratio are studied.Results indicate that under rejection pressures of 6.89,3.45,and 1.88 MPa,the times to establish stable flow are 50,193,and 395 min,respectively.Higher injection pressures lead to an increased oil recovery efficiency,with the highest observed efficiency at 16.93%.This indicates that,compared with conventional medium and high permeability reservoirs,tight oil reservoirs exhibit similar pore throats and larger capillary forces when oil and water flow in both phases.Higher pressures reduce capillary forces,displacing more oil droplets,thus enhancing oil recovery efficiency.Moreover,under inter-fracture displacement conditions,the pressure gradient at both the injection and production ends remain consistent,with minimal pressure loss near the wellbore.This feature ensures that the crude oil in the middle of the reservoir also possesses displacement energy,thereby enhancing overall crude oil displacement efficiency.
基金granted by the National Program on Key Basic Research Project(973 Program)(grant No. 2014CB239000)State Oil and Gas Major Project(grant No.2011ZX05001)+1 种基金CNPC Major Project(grant No. 2016B-0301-04)financially supported by the Ministry of Science and Technology of China
文摘The Upper Triassic oil accumulations in the Ordos Basin is the most successful tight oil play in China,with average porosity values of less than 10% and permeability values below 1.0 mD.This study investigated the geological characteristics and origin of the tight oil accumulations in the Chang 6 member of the Upper Triassic Yanchang Formation in the Shanbei area based on over 50,000 petrological,source-rock analysis,well logging and production data.The tight oil accumulation of the Chang 6 member is distributed continuously in the basin slope and the centre of the basin.The oilwater relationships are complex.Laumontite dissolution pores are the most important storage spaces,constituting 30%-60% of total porosity and showing a strong positive relationship with oil production.The pore-throat diameter is less than 1 μm,and the calculated critical height of the oil column is much larger than the tight sand thickness,suggesting that the buoyancy was probably of limited importance for oil migration.The pressure difference between the source rocks and sandstone reservoirs is inferred to have provided driving force for hydrocarbon migration.Two factors of source-reservoir configuration and laumontite dissolution contributed to the formation of the Chang 6 tight oil accumulations.Intense hydrocarbon generation and continuous sand bodies close to the hydrocarbon kitchen are the foundation for the large-scale oil distribution.Dissolution of feldspar-laumontite during the process of organic matter evolution generated abundant secondary pores and improved the reservoir quality.
基金supported by the National Key Basic Research and Development Program (973 Program), China (Grant 2014CB239000)China National Science and Technology Major Project (Grant 2011ZX05001)
文摘Tight oil has become the focus in exploration and development of unconventional oil in the world, especially in North America and China. In North America, there has been intensive exploration for tight oil in marine. In China, commercial exploration for tight oil in conti- nental sediments is now steadily underway. With the dis- covery of China＇s first tight oil field--Xin＇anbian Oilfield in the Ordos Basin, tight oil has been integrated officially into the category for reserves evaluation. Geologically, tight oil is characterized by distribution in depressions and slopes of basins, extensive, mature, and high-quality source rocks, large-scale reservoir space with micro- and nanopore throat systems, source rocks and reservoirs in close contact and with continuous distribution, and local ＂sweet area.＂ The evaluation of the distribution of tight oil ＂sweet area＂ should focus on relationships between ＂six features.＂ These are source properties, lithology, physical properties, brittleness, hydrocarbon potential, and stress anisotropy. In North America, tight oil prospects are distributed in lamellar shale or marl, where natural fractures are fre- quently present, with TOC 〉 4 %, porosity 〉 7 %, brittle mineral content 〉 50 %, oil saturation of 50 %-80 %, API 〉 35~, and pressure coefficient 〉 1.30. In China, tight oil prospects are distributed in lamellar shale, tight sand- stone, or tight carbonate rocks, with TOC 〉 2 %, poros- ity 〉 8 %, brittle mineral content 〉 40 %, oil saturation of 60 %-90 %, low crude oil viscosity, or high formation pressure. Continental tight oil is pervasive in China and its preliminary estimated technically recoverable resources are about （20-25） × lO8^ t.
基金supported by the Natural Science Foundation of China (Grant No. 51574257)National 973 Project (No. 2015CB250900)
文摘Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the development efficiency of block matrix, surfactant-aided imbibition is a potential way. The current work aimed to explain comprehensively how surfactants can enhance the imbibition rate. Laboratory experiments were performed to investigate the effects of wettability, interfacial tension(IFT), and relative permeability as the key parameters underlying surfactant solution imbibition. Two different types of surfactants, sodium dodecyl sulfate and polyethylene glycol octylphenol ether, at varied concentrations were tested on reservoir rocks. Experimental results showed that the oil recovery rate increased with increased wettability alteration and IFT and decreased residual oil saturation. A mechanistic simulator developed in previous studies was used to perform parametric analysis after successful laboratory-scale validation. Results were proven by parametric studies. This study,which examined the mechanism and factors influencing surfactant solution imbibition, can improve understanding of surfactant-aided imbibition and surfactant screening.
基金supported by the Chinese Major National Scientific and Technological Program (2011ZX05001)Chinese Postdoctoral Fund (2013M540114)
文摘In exploration for tight oil, the content and saturation of hydrocarbon in the tight reservoir is a key factor for evaluating the reserve. Therefore, it is necessary to study the geological history of hydrocarbon accumulation and the tight oil charging process. However, kinetic models used for petroleum development are not applicable for petroleum exploration. In this study, a static resistance model[ is proposed after analyzing resistances in ultra-slow flow in porous media. Using this model, the disco^atinuous pattern of oil charging is reproduced through incompressible Navier-Stokes equations, the phase field method and the finite element method. This study also explains macroscopic percolation behavior with microscopic flow mechanisms and discusses some issues in ultra-slow flow in a micro/nano pore-throat network. The resistance analysis reveals that capillary resistance and dissipation resistance are dominant factors in the mechanism of oil accumulation in tight reservoirs. Numerical simulations show that pressure thresholds exist and result in discontinuous oil charging. Generally, it is proven that the static model is more applicable than kinetic models in describing oil accumulation in tight reservoirs.
文摘Volumetric fracturing is a primary stimulation technology for economical and effective exploitation of tight oil reservoirs. The main mechanism is to connect natural fractures to generate a fracture network system which can enhance the stimulated reservoir volume. By using the combined finite and discrete element method, a model was built to describe hydraulic fracture propagation in tight oil reservoirs. Considering the effect of horizontal stress difference, number and spacing of perforation clus- ters, injection rate, and the density of natural fractures on fracture propagation, we used this model to simulate the fracture propagation in a tight formation of a certain oil- field. Simulation results show that when the horizontal stress difference is lower than 5 MPa, it is beneficial to form a complex fracture network system. If the horizontal stress difference is higher than 6 MPa, it is easy to form a planar fracture system; with high horizontal stress differ- ence, increasing the number of perforation clusters is beneficial to open and connect more natural fractures, and to improve the complexity of fracture network and the stimulated reservoir volume （SRV）. As the injection rate increases, the effect of volumetric fracturing may be improved; the density of natural fractures may only have a great influence on the effect of volume stimulation in a low horizontal stress difference.
文摘Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs,especially in the US.However,the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery factor.Therefore,the application of EOR in the early reservoir development phase is considered effective for fast-paced and economical tight oil recovery.To achieve these objectives,it is imperative to determine the optimum EOR potential and the best-suited EOR application for every individual tight oil reservoir to maximize its ultimate recovery factor.Since most of the tight oil reservoirs are found in wide spatial source rock with complex and compacted pores and poor geophysical properties yet they hold high saturation of good quality oil and therefore,every single percent increase in oil recovery from such huge reservoirs potentially provide an additional million barrels of oil.Hence,the EOR application in such reservoirs is quite essential.However,the physical understanding of EOR applications in different circumstances from laboratory to field scale is the key to success and similarly,the fundamental physical concepts of fluid flow-dynamics under confinement conditions play an important role.This paper presents a detailed discussion on laboratory-based experimental achievements at micro-scale including fundamental concepts under confinement environment,physics-based numerical studies,and recent actual field piloting experiences based on the U.S.unconventional plays.The objective of this paper is to discuss all the critical reservoir rock and fluid properties and their contribution to reservoir development through massive multi-staged hydraulic fracture networks and the EOR applications.Especially the CO_(2)and produced hydrocarbon gas injection through single well-based huff-n-puff operational constraints are discussed in detail both at micro and macro scale.
基金financial support from the National Natural Science Foundation of China(No.51974282,52074249,51874261)Fundamental Research Funds for the Central Universities(2-9-2019-103)Key Research and Development Program of Shaanxi(No.2021GY-112)。
文摘Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water distribution in rocks during imbibition using various nanofluids was less discussed in previous studies.In this study,we systematically examined the imbibition efficiencies of various nanofluids at60℃.Furthermore,the migration of nanofluids and oil distribution in the rock pores were monitored using nuclear magnetic resonance(NMR).The nanofluids were prepared by dispersing silica nanoparticles and five different types of surfactants i.e.,anionic-nonionic,anionic,nonionic,amphoteric and cationic surfactants in deionized(DI)water.Subsequently,interfacial tension(IFT)and contact angle measurements were conducted to reveal the underlying EOR mechanisms of various nanofluids.The experimental results showed that the EOR potential of the different types of nanofluids was in the order anionic-nonionic>anionic>nonionic>amphoteric>cationic>brine.Anionic-nonionic(sodium lauryl ether sulfate(SLES))and anionic(sodium dodecyl sulfonate(SDS))nanofluids exhibited excellent capability of wettability alteration,and increased oil recovery by 27.96%and 23.08%,respectively,compared to brine.The NMR results also showed that mesopores(0.1-1μm)were the dominant developed pores in the rocks,and contributed the most to imbibition efficiency.In addition,the imbibition of nanofluids initially took place in mesopores and micropores before moving into macropores.This study provides fundamental information on the selection of nanofluids for EOR in tight oil reservoirs.The study also improved the understanding of oil/water distribution during the imbibition of the proposed nanofluids.
基金Projects(51204054,51504203)supported by the National Natural Science Foundation of ChinaProject(2016ZX05023-001)supported by the National Science and Technology Major Project of China
文摘The selection of refracturing candidate is one of the most important jobs faced by oilfield engineers. However, due to the complicated multi-parameter relationships and their comprehensive influence, the selection of refracturing candidate is often very difficult. In this paper, a novel approach combining data analysis techniques and fuzzy clustering was proposed to select refracturing candidate. First, the analysis techniques were used to quantitatively calculate the weight coefficient and determine the key factors. Then, the idealized refracturing well was established by considering the main factors. Fuzzy clustering was applied to evaluate refracturing potential. Finally, reservoirs numerical simulation was used to further evaluate reservoirs energy and material basis of the optimum refracturing candidates. The hybrid method has been successfully applied to a tight oil reservoir in China. The average steady production was 15.8 t/d after refracturing treatment, increasing significantly compared with previous status. The research results can guide the development of tight oil and gas reservoirs effectively.
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 Science and Technology Major Project (2017ZX05013-005)。
文摘A mathematical model, fully coupling multiple porous media deformation and fluid flow, was established based on the elastic theory of porous media and fluid-solid coupling mechanism in tight oil reservoirs. The finite element method was used to determine the numerical solution and the accuracy of the model was verified. On this basis, the model was used to simulate productivity of multistage fractured horizontal wells in tight oil reservoirs. The results show that during the production of tight oil wells, the reservoir region close to artificial fractures deteriorated in physical properties significantly, e.g. the aperture and conductivity of artificial fractures dropped by 52.12% and 89.02% respectively. The simulations of 3000-day production of a horizontal well in tight oil reservoir showed that the predicted productivity by the uncoupled model had an error of 38.30% from that by the fully-coupled model. Apparently, ignoring the influence of fluid-solid interaction effect led to serious deviations of the productivity prediction results. The productivity of horizontal well in tight oil reservoir was most sensitive to the start-up pressure gradient, and second most sensitive to the opening of artificial fractures. Enhancing the initial conductivity of artificial fractures was helpful to improve the productivity of tight oil wells. The influence of conductivity, spacing, number and length of artificial fractures should be considered comprehensively in fracturing design. Increasing the number of artificial fractures unilaterally could not achieve the expected increase in production.
基金Supported by the National Natural Science Foundation of China(41672118)Strategic Cooperation Science and Technology Project Between China University of Petroleum and Petro China(ZLZX2020-01-06)。
文摘Taking the tight oil of the Zhongnan sag in the Ordos Basin,Jimusar sag in the Junggar Basin and Qingxi sag in the Jiuquan Basin as study objects,based on field survey,dissection of tight oil reservoirs,sample test,modeling experiment and comprehensive analysis,this study reveals that the tight oil accumulates at start-up pressure,advances under differential pressure,diffuses at alternating fast and low speeds,charges in stepped large area and migrates rapidly through fractures,and enriches in dominant fractures and pores.The root cause of ladder-like charge is the multiple scales of pores.The widespread source rock with high hydrocarbon generation intensity is the material basis for tight oil enrichment;the dominant source reservoir assemblage is the basic unit for tight oil enrichment;fractures and beddings are conducive to local rapid migration of tight oil;fractures and pores work together to control the enrichment of tight oil.Two typical accumulation models of tight oil are established,namely"source reservoir in coexistence,four optimal factors controlling enrichment around central area,and large-scale continuous distribution"for a large freshwater lake clastic rock basin and"source reservoir integration,four optimal factors controlling enrichment,central area distribution,small in size but high in enrichment degree"for a small saline lake diamictite depression.
基金financially supported by the Chinese National Special Plan Project"Formation conditions,enrichment regularity and resource potential of tight oil”(No.2016ZX05046-001)。
文摘Xin’anbian Oilfield of the Ordos Basin is the large tight oilfield to be first exploration discovery in china.The production of tight oil increased significantly in recent years.It shows great exploration potential of Chang 7 tight oil.But the physical property and hydrocarbon enrichment characteristics of Chang 7 tight oil reservoirs were rarely studied,The forming conditions of tight oil reservoirs are systematically summarized and analyzed through the study of hydrocarbon generation,sedimentary reservoirs and hydrocarbon migration and accumulation based on production and core experimental data.The result shows that,The porosity of the Chang 7_(2)reservoir mainly distributed in 5.0-11.0%,average at 7.9%,The permeability mainly distributed in 0.04-0.18×10^(-3)μm^(2),average at 0.12×10^(-3)μm^(2),The pore diameters of the tight oil reservoir distributed in 2-8μm.The high-quality Chang 7_(3)source rocks and the micropsammite of Chang 7_(2)subaqueous distributary channel were widely distributed in the study area.The lenticular or banded sand bodies are distributed among mudstone or hydrocarbon source rocks and have the advantage of migration distance for hydrocarbon accumulation.The reservoir space is composed of micro-nanometer pores and throat,that is formed in the process of increasing pressure during hydrocarbon generation and hydrocarbon accumulation.The Chang 7 tight oil was generated in the early Cretaceous and injected into the sand of the subaqueous distributary channel driven by continuous hydrocarbon generation supercharging.The formation and accumulation of tight oil reservoirs are mainly controlled by source rocks,sedimentary microfacies and reservoirs of good quality.
基金This work was jointly supported by National Natural Science Foundation of China(Grant No.41902132,11872363,51861145314)PetroChina Innovation Foundation(Grant No.2019D-5007-0214)+2 种基金Chinese Academy of Sciences(CAS)through the CAS Key Research Program of Frontier Sciences(Grant No.QYZDJ-SSW-JSC019)the CAS Strategic Priority Research Program(Grant No.XDB22040401)National Science and Technology Mega Project of China(Grant No.2017ZX05013005-009).
文摘This study aimed to investigate the complete distribution of reservoir space in tight oil sandstone combining casting slices, field emission scanning electron microscopy(FE-SEM), the pore-throat theory model, high-resolution image processing, mathematical statistics, and other technical means. Results of reservoir samples from the Xin’anbian area of Ordos Basin showed that the total pore radius curve of the tight oil sandstone reservoir exhibited a multi-peak distribution, and the peaks appeared to be more focused on the ends of the range. This proved that pores with a radius of 1–50,000 nm provided the most significant storage space for tight oil, indicating that special attention should be paid to this range of the pore size distribution. Meanwhile, the complete throat radius curve of the tight oil sandstone reservoir exhibited a multipeak distribution. However, the peak values were distributed throughout the scales. This confirmed that the throat radius in the tight oil sandstone reservoir was not only in the range of hundreds of nanometers but was also widely distributed in the scale approximately equal to the pore size. The new rapid determination method could provide a precise theoretical basis for the comprehensive evaluation, exploration, and development of a tight oil sandstone reservoir.
基金financial support from the National Natural Science Foundation of China(52074319)the Strategic Cooperation Technology Project of CNPC(ZLZX2020-01-08)the Science Foundation of China University of Petroleum-Beijing(2462021QNXZ008)
文摘Nitrogen huff-n-puff(N_(2)HnP) appears to be an economical and high-efficiency enhanced oil recovery(EOR) technique for tight oil reservoirs.There is however a lack of understanding of the pore-level EOR performance of N2HnP under tight reservoir conditions.In this work,a non-magnetic reactor was created and combined with a nuclear magnetic resonance(NMR) device for real-time monitoring of oil distribution in the HnP experiment.N_(2)HnP experiments were then performed in a tight sandstone core sample at a temperature of 353 K and an injection pressure≥ 24 MPa.The pore-level oil distribution under reservoir conditions was monitored and the EOR performance of N2HnP in specific pores was analyzed.The pore throat structures of the core sample and the phase behavior of the N_(2)-Oil system were analyzed to elucidate the EOR mechanism of N_(2)HnP.An oil recovery factor of 37.52% can be achieved after four cycles,which proves the EOR potential of N_(2)HnP for tight reservoirs.The highest recoveries after N_(2)HnP are obtained in the large pores,followed by the medium pores,the small pores,and finally the micro pores.Increases in soaking time and injection pressure resulted in slight and pronounced increases in oil recovery,respectively,both of which are mainly reflected in the first cycle.Specifically,increasing the soaking time only slightly improves the cumulative oil recovery in the small pores while increasing the injection pressure significantly improves the cumulative oil recovery in the small,medium,and large pores simultaneously.However,variations in both injection pressure and soaking time have a negligible effect on the cumulative oil recovery of the micro pores.
文摘CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO_(2)huff and puff and the contribution of sweeping mode to recovery.The experimental results show that the development process of CO_(2)huff and puff can be divided into four stages,namely,CO_(2)backflow,production of gas with some oil,high-speed oil production,and oil production rate decline stages.The production of gas with some oil stage is dominated by free gas displacement,and the high-speed oil production stage is dominated by dissolved gas displacement.CO_(2)injection volume and development speed are the major factors affecting the oil recovery.The larger the injected CO_(2)volume and the lower the development speed,the higher the oil recovery will be.The reasonable CO_(2)injection volume and development speed should be worked out according to oilfield demand and economic evaluation.There is a reasonable soaking time in CO_(2)huff and puff.Longer soaking time than the optimum time makes little contribution to oil recovery.In field applications,the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period.The oil recovery of CO_(2)huff and puff mainly comes from the contribution of flow sweep and diffusion sweep,and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.
基金Supported by the National Science and Technology Major Project(2016ZX05046-001-005)National Natural Science Foundation of China(41922015)。
文摘Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China,such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin,NE China sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin,NE China the theoretical lower limit,oil accumulation lower limit,effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method,oil bearing occurrence method,oil testing productivity method and mechanical balance method,respectively.Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs,determine the grading criterion of tight reservoirs,and analyze its correlation with the limit of reservoir formation.The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties,the boundary of classⅡand classⅢtight reservoirs corresponds to the lower limit of effective flow,the boundary of classⅢand classⅣtight reservoirs corresponds to the lower limit of reservoir forming,and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir.Finally,the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir,and classⅠand classⅡtight reservoirs are the favorable sections for high production of tight oil.
基金sincerely appreciate the financial support from the National Key Research and Development Project(2019YFA0708700)the National Natural Science Foundation of China(51834010,51874261,51874337)+1 种基金the Key Research and Development Program of Shaanxi(2021GY-112)a Discovery Grant from Natural Sciences and Engineering Research Council of Canada(NSERC RGPIN-2017-05080).
文摘The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies,such as low recovery efficiency,rapid production decline,high cost,and complexity,etc.Therefore,a new technology,the so-called fracturing-oil expulsion integration,which does not need flowback after fracturing while making full use of the fracturing energy and gel breaking fluids,are needed to enable efficient exploitation of tight oil.A novel triple-responsive smart fluid based on“pseudo-Gemini”zwitterionic viscoelastic surfactant(VES)consisting of N-erucylamidopropyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate(EHSB),N,N,N′,N′-tetramethyl-1,3-propanediamine(TMEDA)and sodium p-toluenesulfonate(NaPts),is developed.Then,the rheology of smart fluid is systematically studied at varying conditions(CO_(2),temperature and pressure).Moreover,the mechanism of triple-response is discussed in detail.Finally,a series of fracturing and spontaneous imbibition performances are systematically investigated.The smart fluid shows excellent CO_(2)-,thermal-,and pressure-triple responsive behavior.It can meet the technical requirement of tight oil fracturing construction at 140°C in the presence of 3.5 MPa CO_(2).The gel breaking fluid shows excellent spontaneous imbibition oil expulsion(∼40%),salt resistance(1.2×104 mg/L Na+),temperature resistance(140°C)and aging stability(30 days).
