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Microscopic characteristics of tight sandstone reservoirs and their effects on the imbibition efficiency of fracturing fluids:A case study of the Linxing area,Ordos Basin 被引量:1
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作者 Qihui Li Dazhong Ren +6 位作者 Hu Wang Haipeng Sun Tian Li Hanpeng Zhang Zhen Yan Rongjun Zhang Le Qu 《Energy Geoscience》 EI 2024年第3期328-338,共11页
The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved ... The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation(also referred to as the He 8 Member)in the study area,as well as their effects on fracturing fluid imbibition.Utilizing experimental techniques such as nuclear magnetic resonance(NMR),high-pressure mercury intrusion(HPMI),and gas adsorption,this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments.The findings reveal that:①The reservoir,with average porosity of 8.40%and average permeability of 0.642×10^(-3)μm^(2),consists principally of quartz,feldspar,and lithic fragments,with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral;②Nano-scale micro-pores and throats dominate the reservoir,with dissolution pores and intercrystalline pores serving as predominant pore types,exhibiting relatively high pore connectivity;③Imbibition efficiency is influenced by petrophysical properties,clay mineral content,and microscopic pore structure.Due to the heterogeneity of the tight sandstone reservoir,microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids;④A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency,followed by petrophysical properties and clay mineral content.In contrast,the pore type has minimal impact.Micropores are vital in the imbibition process,while meso-pores and macro-pores offer primary spaces for imbibition.This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones. 展开更多
关键词 Tight sandstone Ordos Basin fracturing fluid Microscopic reservoir characteristics Imbibition efficiency Influencing factor
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Influences of clean fracturing fluid viscosity and horizontal in-situ stress difference on hydraulic fracture propagation and morphology in coal seam
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作者 Gang Wang Shuxin Wang +5 位作者 Yixin Liu Qiming Huang Shengpeng Li Shuliang Xie Jinye Zheng Jiuyuan Fan 《International Journal of Coal Science & Technology》 EI CAS CSCD 2024年第3期159-175,共17页
The viscosity of fracturing fluid and in-situ stress difference are the two important factors that affect the hydraulic fracturing pressure and propagation morphology. In this study, raw coal was used to prepare coal ... The viscosity of fracturing fluid and in-situ stress difference are the two important factors that affect the hydraulic fracturing pressure and propagation morphology. In this study, raw coal was used to prepare coal samples for experiments, and clean fracturing fluid samples were prepared using CTAB surfactant. A series of hydraulic fracturing tests were conducted with an in-house developed triaxial hydraulic fracturing simulator and the fracturing process was monitored with an acoustic emission instrument to analyze the influences of fracturing fluid viscosity and horizontal in-situ stress difference on coal fracture propagation. The results show that the number of branched fractures decreased, the fracture pattern became simpler, the fractures width increased obviously, and the distribution of AE event points was concentrated with the increase of the fracturing fluid viscosity or the horizontal in-situ stress difference. The acoustic emission energy decreases with the increase of fracturing fluid viscosity and increases with the increase of horizontal in situ stress difference. The low viscosity clean fracturing fluid has strong elasticity and is easy to be compressed into the tip of fractures, resulting in complex fractures. The high viscosity clean fracturing fluids are the opposite. Our experimental results provide a reference and scientific basis for the design and optimization of field hydraulic fracturing parameters. 展开更多
关键词 Clean fracturing fluid Hydraulic fracturing VISCOSITY Horizontal in-situ stress difference Hydraulic fracture morphology Acoustic emission
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Optimization method of fracturing fluid volume intensity for SRV fracturing technique in shale oil reservoir based on forced imbibition:A case study of well X-1 in Biyang Sag of Nanxiang Basin,China
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作者 JIANG Tingxue SHEN Ziqi +6 位作者 WANG Liangjun QI Zili XIAO Bo QIN Qiuping FAN Xiqun WANG Yong QU Hai 《Petroleum Exploration and Development》 SCIE 2024年第3期674-683,共10页
An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were ob... An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing.The optimization of the stimulated reservoir volume(SRV)fracturing fluid volume strength should meet the requirements of estimated ultimate recovery(EUR),increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount.Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed,above which the single-well EUR increase rate kept decreasing.An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production.Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production. 展开更多
关键词 shale oil horizontal well volume fracturing forced imbibition fracturing fluid intensity parameter optimization
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Formation damage mechanism and control strategy of the compound function of drilling fluid and fracturing fluid in shale reservoirs
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作者 SUN Jinsheng XU Chengyuan +6 位作者 KANG Yili JING Haoran ZHANG Jie YANG Bin YOU Lijun ZHANG Hanshi LONG Yifu 《Petroleum Exploration and Development》 SCIE 2024年第2期430-439,共10页
For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid,the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture ... For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid,the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid.With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface,fracture closure and rock powder blocking,the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid.The formation damage mechanism during drilling and completion process in shale reservoir is revealed,and the protection measures are raised.The drilling fluid can deeply invade into the shale formation through natural and induced fractures,erode shale minerals and weaken the mechanical properties of shale during the drilling process.In the process of hydraulic fracturing,the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale,results in fracture closure and rock powder shedding,and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures.The damage can yield significant conductivity decrease of fractures,and restrict the high and stable production of shale oil and gas wells.The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section,forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface,strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid,optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection. 展开更多
关键词 shale oil and gas drilling fluid fracturing fluid stress-sensitive solid blocking formation damage reservoir protection
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Supramolecular polymer-based gel fracturing fluid with a double network applied in ultra-deep hydraulic fracturing
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作者 Yong-Ping Huang Yong Hu +5 位作者 Chang-Long Liu Yi-Ning Wu Chen-Wei Zou Li-Yuan Zhang Ming-Wei Zhao Cai-Li Dai 《Petroleum Science》 SCIE EI CAS CSCD 2024年第3期1875-1888,共14页
A gel based on polyacrylamide,exhibiting delayed crosslinking characteristics,emerges as the preferred solution for mitigating degradation under conditions of high temperature and extended shear in ultralong wellbores... A gel based on polyacrylamide,exhibiting delayed crosslinking characteristics,emerges as the preferred solution for mitigating degradation under conditions of high temperature and extended shear in ultralong wellbores.High viscosity/viscoelasticity of the fracturing fluid was required to maintain excellent proppant suspension properties before gelling.Taking into account both the cost and the potential damage to reservoirs,polymers with lower concentrations and molecular weights are generally preferred.In this work,the supramolecular action was integrated into the polymer,resulting in significant increases in the viscosity and viscoelasticity of the synthesized supramolecular polymer system.The double network gel,which is formed by the combination of the supramolecular polymer system and a small quantity of Zr-crosslinker,effectively resists temperature while minimizing permeability damage to the reservoir.The results indicate that the supramolecular polymer system with a molecular weight of(268—380)×10^(4)g/mol can achieve the same viscosity and viscoelasticity at 0.4 wt%due to the supramolecular interaction between polymers,compared to the 0.6 wt%traditional polymer(hydrolyzed polyacrylamide,molecular weight of 1078×10^(4)g/mol).The supramolecular polymer system possessed excellent proppant suspension properties with a 0.55 cm/min sedimentation rate at 0.4 wt%,whereas the0.6 wt%traditional polymer had a rate of 0.57 cm/min.In comparison to the traditional gel with a Zrcrosslinker concentration of 0.6 wt%and an elastic modulus of 7.77 Pa,the double network gel with a higher elastic modulus(9.00 Pa)could be formed only at 0.1 wt%Zr-crosslinker,which greatly reduced the amount of residue of the fluid after gel-breaking.The viscosity of the double network gel was66 m Pa s after 2 h shearing,whereas the traditional gel only reached 27 m Pa s. 展开更多
关键词 Ultra-deep reservoir Gel fracturing fluid Double network Supramolecular polymer system Proppant suspension property
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A Novel Fracturing Fluid with High-Temperature Resistance for Ultra-Deep Reservoirs
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作者 Lian Liu Liang Li +2 位作者 Kebo Jiao Junwei Fang Yun Luo 《Fluid Dynamics & Materials Processing》 EI 2024年第5期975-987,共13页
Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do ... Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do not produce satisfactory results when conventional fracturing fluids with a low pumping rate are used.In response to the above problem,a fracturing fluid with a density of 1.2~1.4 g/cm^(3)was developed by using Potassium formatted,hydroxypropyl guanidine gum and zirconium crosslinking agents.The fracturing fluid was tested and its ability to maintain a viscosity of 100 mPa.s over more than 60 min was verified under a shear rate of 1701/s and at a temperature of 175℃.This fluid has good sand-carrying performances,a low viscosity after breaking the rubber,and the residue content is less than 200 mg/L.Compared with ordinary reconstruction fluid,it can increase the density by 30%~40%and reduce the wellhead pressure of 8000 m level reconstruction wells.Moreover,the new fracturing fluid can significantly mitigate safety risks. 展开更多
关键词 Ultra-deep reservoir high-temperature resistance weighted fracturing fluid guanidine gum potassium formatted
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Research on the Performance of New Weighted Slippery Water Fracturing Fluid System
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作者 Yuanfan Shi Weichu Yu +5 位作者 Dongkui Zhou Fei Ding Wengming Shu Ying Zhang Yiwen Ju Zhengdong Lei 《Open Journal of Applied Sciences》 2024年第8期2101-2111,共11页
Deep and ultra-deep reservoirs have dense matrix and high fracture pressure, which leads to high pressure and difficulty in fracturing construction. Conventional aggravated fracturing fluids have the problems of low a... Deep and ultra-deep reservoirs have dense matrix and high fracture pressure, which leads to high pressure and difficulty in fracturing construction. Conventional aggravated fracturing fluids have the problems of low aggravation efficiency, high friction resistance, etc., and the reduction of construction pressure cannot reach the theoretical effect. In view of the above problems, this paper adopts the weighting agent HD160 and the drag reducing agent JHFR-2 to form a new type of weighted slippery water fracturing fluid system. And the weighting performance, drag reduction performance, corrosion performance, anti-expansion performance and reservoir damage of this system were studied. The results show that the density of the system is adjustable within 1.1 - 1.6 g·cm−3, and the drag reduction rate can be up to 68% at 1.5 g·cm−3, with low corrosion rate, surface tension less than 28 mN·m−1, anti-expansion rate as high as 94.5%, and the damage rate of the reservoir permeability is less than 10%, which is of good application prospect. 展开更多
关键词 Aggravated fracturing fluid Aggravator Slickwater Corrosive Properties Anti-Swelling Rate
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A review of reservoir damage during hydraulic fracturing of deep and ultra-deep reservoirs 被引量:2
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作者 Kun Zhang Xiong-Fei Liu +6 位作者 Dao-Bing Wang Bo Zheng Tun-Hao Chen Qing Wang Hao Bai Er-Dong Yao Fu-Jian Zhou 《Petroleum Science》 SCIE EI CAS CSCD 2024年第1期384-409,共26页
Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide.These reservoirs present u... Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide.These reservoirs present unique challenges due to their deep burial depth(4500-8882 m),low matrix permeability,complex crustal stress conditions,high temperature and pressure(HTHP,150-200℃,105-155 MPa),coupled with high salinity of formation water.Consequently,the costs associated with their exploitation and development are exceptionally high.In deep and ultra-deep reservoirs,hydraulic fracturing is commonly used to achieve high and stable production.During hydraulic fracturing,a substantial volume of fluid is injected into the reservoir.However,statistical analysis reveals that the flowback rate is typically less than 30%,leaving the majority of the fluid trapped within the reservoir.Therefore,hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved.The challenging“three-high”environment of a deep reservoir,characterized by high temperature,high pressure,and high salinity,exacerbates conventional forms of damage,including water sensitivity,retention of fracturing fluids,rock creep,and proppant breakage.In addition,specific damage mechanisms come into play,such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions.Presently,the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing,comprehending the underlying mechanisms,and selecting appropriate solutions.It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs,with limited attention given to deep reservoirs and a lack of systematic summaries.In light of this,our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs.Subsequently,we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs,taking into account the unique reservoir characteristics of high temperature,high pressure,and high in-situ stress.In addition,we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix,both artificial and natural fractures,and sand-packed fractures.We conclude by offering a summary of current research advancements and future directions,which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage. 展开更多
关键词 Artificial fracture Deep and ultra-deep reservoir fracture conductivity fracturing fluid Hydraulic fracturing Reservoir damage
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Effect of fracture fluid flowback on shale microfractures using CT scanning 被引量:2
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作者 Jiale He Zhihong Zhao +6 位作者 Yiran Geng Yuping Chen Jianchun Guo Cong Lu Shouyi Wang Xueliang Han Jun Zhang 《Journal of Rock Mechanics and Geotechnical Engineering》 SCIE CSCD 2024年第2期426-436,共11页
The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that o... The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs.At the early stage of flowback,there is no single-phase flow of the liquid phase in shale,but rather a gas-water two-phase flow,such that the single-phase flow model for tight oil and gas reservoirs is not applicable.In this study,pores and microfractures are extracted based on the experimental results of computed tomography(CT)scanning,and a spatial model of microfractures is established.Then,the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law,which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness.The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method(LBM).The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures,which explains the low fracturing fluid flowback rate in shale hydraulic fracturing. 展开更多
关键词 SHALE Flowback of fracturing fluid MICROfracturE Lattice Boltzmann method(LBM)
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Probing the influence of secondary fracture connectivity on fracturing fluid flowback efficiency 被引量:3
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作者 Yi-Ning Wu Li-Sha Tang +5 位作者 Yuan Li Li-Yuan Zhang Xu Jin Ming-Wei Zhao Xiang Feng Cai-Li Dai 《Petroleum Science》 SCIE EI CAS CSCD 2023年第2期973-981,共9页
A deep understanding of the geometric impacts of fracture on fracturing fluid flowback efficiency is essential for unconventional oil development. Using nuclear magnetic resonance and 2.5-dimensional matrix-fracture v... A deep understanding of the geometric impacts of fracture on fracturing fluid flowback efficiency is essential for unconventional oil development. Using nuclear magnetic resonance and 2.5-dimensional matrix-fracture visualization microfluidic models, qualitative and quantitative descriptions of the influences of connectivity between primary fracture and secondary fracture on flowback were given from core scale to pore network scale. The flow patterns of oil-gel breaking fluid two-phase flow during flowback under different fracture connectivity were analyzed. We found some counterintuitive results that non-connected secondary fracture (NCSF, not connect with artificial primary fracture and embedded in the matrix) is detrimental to flowbackefficiency. The NCSF accelerates the formation of oil channeling during flowback, resulting in a large amount of fracturing fluid trapped in the matrix, which is not beneficial for flowback. Whereas the connected secondary fracture (CSF, connected with the artificial primary fracture) is conducive to flowback. The walls of CSF become part of primary fracture, which expands the drainage area with low resistance, and delays the formation of the oil flow channel. Thus, CSF increases the high-speed flowback stage duration, thereby enhancing the flowback efficiency. The fracturing fluid flowback efficiency investigated here follows the sequence of the connected secondary fracture model (72%) > the matrix model (66%) > the non-connected secondary fracture model (38%). Our results contribute to hydraulic fracturing design and the prediction of flowback efficiency. 展开更多
关键词 fracturing fluid Secondary fracture connectivity Flowback efficiency Dual media Microfluidic model
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A novel triple responsive smart fluid for tight oil fracturing-oil expulsion integration 被引量:2
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作者 Ming-Wei Gao Ming-Shan Zhang +5 位作者 Heng-Yi Du Ming-Wei Zhao Cai-Li Dai Qing You Shun Liu Zhe-Hui Jin 《Petroleum Science》 SCIE EI CAS CSCD 2023年第2期982-992,共11页
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
关键词 fracturing-oil expulsion integration Tight oil Triple responsive smart fluid "Pseudo-gemini"zwitterionic surfactant fracturing fluid Spontaneous imbibition
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The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS_(2)nanosheets 被引量:2
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作者 Hang Xu Yuan Li +6 位作者 Guo-Lin Yu Sa-Sa Yang Bo-Jun Li Fu-Jian Zhou Er-Dong Yao Hao Bai Zhi-Yu Liu 《Petroleum Science》 SCIE EI CAS CSCD 2023年第4期2187-2201,共15页
Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing;however,lots of challenges and limitations such as low viscosity,poor salt tolerance,and possi... Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing;however,lots of challenges and limitations such as low viscosity,poor salt tolerance,and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid.In addition,nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater.In this paper,molybdenum disulfide(MoS_(2))nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid.Firstly,the microstructure characteristics and crystal type of the MoS_(2)nanosheets were analyzed by SEM,EDS,TEM,XPS,and Raman spectroscopy techniques.Then,a series of evaluation experiments were carried out to compare the performance of MoS_(2)nanosheet-modified slickwater with the conventional slickwater,including rheology,drag reduction,and sand suspension.Finally,the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated.The results showed that the self-synthesized MoS_(2)nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers.In the nano-composites,each MoS_(2)nanosheet plays the role of cross-linking point,so as to make the spatial structure of the entire system more compact.Moreover,nanosheet-modified slickwater demonstrates more excellent properties in rheology,drag reduction,and sand suspension.The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90℃ and 170 s^(−1).The maximum drag reduction rate achieved 76.3%at 20℃,and the sand settling time of proppants with different mesh in the nano-composites was prolonged.Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching,and increase the oil recovery to∼35.43%.By observing and analyzing the interfacial behavior of MoS_(2)nanosheets under stimulated reservoir conditions,it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism.This work innovatively uses two-dimensional MoS_(2)nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater.The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites. 展开更多
关键词 Slickwater-based fracturing fluid MoS_(2)nanosheet Performance evaluation spontaneous imbibition Climbing film
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Preparation of a functional fracturing fluid with temperature-and salt-resistance,and low damage using a double crosslinking network 被引量:1
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作者 Yang Zhang An Chen +6 位作者 Jin-Cheng Mao Song-Hai Qin Jin Li Xiao-Jiang Yang Chong Lin Zhi-Yu Huang Ya-Fei Liu 《Petroleum Science》 SCIE EI CSCD 2023年第5期3223-3230,共8页
Fracturing fluids(FFs)have been widely used to stimulate the tight reservoir.However,current FFs will not only lose their rheological property at high temperatures and high salt but also show an incomplete gel-breakin... Fracturing fluids(FFs)have been widely used to stimulate the tight reservoir.However,current FFs will not only lose their rheological property at high temperatures and high salt but also show an incomplete gel-breaking property.Herein,a double crosslinking network FF with pretty superiorities in rheology and low damage to the core was constructed by introducing both physical crosslinking and chemical crosslinking into the system.The construction of double crosslinking networks enhanced the rheology of this functional FF.The particle sizes of gel-breaking fluids are mainly distributed in 1.0e10,000 nm;furthermore,for every 10,000 mg/L increase in salinity,the particle size of the gel-breaking fluid is decreased by almost half.The adsorption capacity(<1.0 mg/g)gradually decreased with the increase of salinity at 20℃.Moreover,the adsorption of gel-breaking fluids on the rock decreased first and then kept stable with temperature increasing at a salinity of ≤30,000 mg/L,however,showed the opposite trend at 40,000 mg/L.The results of rheology,particle size,static adsorption,and core damage showed that this functional FF could be an alternative for the stimulation of a tight reservoir with high temperature and recycling of produced water with high salinity. 展开更多
关键词 fracturing fluid Temperature-and salt-resistance Particle size Static adsorption Low damage
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Comparative assessment of mechanical and chemical fluid diversion techniques during hydraulic fracturing in horizontal wells
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作者 Maunish S.Shah Subhash N.Shah 《Petroleum Science》 SCIE EI CAS CSCD 2023年第6期3582-3597,共16页
The application of fluid diversion during hydraulic fracturing is an evolving technology and has become popular amongst E&P operators over the past few years.The primary objective of the fluid diversion is to impr... The application of fluid diversion during hydraulic fracturing is an evolving technology and has become popular amongst E&P operators over the past few years.The primary objective of the fluid diversion is to improve hydraulic fracturing treatment by increasing stimulated reservoir volume and improving hydrocarbon recovery.This is possible by achieving any of the following objectives:creating uniform distribution of treatment slurry within the target zone;treating unstimulated and under-stimulated zones;or by increasing fracture density by creating a complex fracture network.The fluid diversion application is also helpful in decreasing the number of stages(by increasing stage length)for multi-stage plug-n-perf(PnP)fracturing treatment.It is also applied to prevent fracture-driven interactions between adjacent wells,which is currently a major issue,especially in shale.In addition,for successful refracturing treatment,the diverter application is essential for isolating the existing fractures and redirecting the treatment slurry to the desired unstimulated zones.The diversion methods can be broadly categorized into the mechanical and chemical diversion.Several established mechanical diversion techniques are frac plugs,expandable casing patches,expandable liners,swellable packers,straddle packer assembly,sand plugs,frac sleeves,perforation ball sealers,and limited entry technique.The different chemical diversion techniques are particulates,fibers,gels,surfactants,perforation pods,and composite diverting.This paper describes the current status of established mechanical and chemical diverter technologies and examines their comparative advantages and challenges.Various techniques are suitable for diverter application,but the technique is selected based on the desired objective and conditions of the wellbore and reservoir.The general guidelines for selecting diversion techniques and operational considerations are also provided in the paper.The diagnosis of diversion treatment plays an essential role in diversion technique selection and optimization of selection parameters for the subsequent treatments.Therefore,the application of conventional surface pressure monitoring techniques and advanced diagnostic tools to evaluate diversion effectiveness are briefly described.Presently no standard laboratory testing method is established for the performance evaluation of diverting agents.Therefore,researchers have implemented various laboratory methods,which are briefly summarized in the paper.Significant insight into the diversion technology and guidelines for its selection and successful implementation is provided to help engineers to increase the effectiveness of hydraulic fracturing treatments.The limitations of individual diversion techniques are clarified,which provide the future scope of research for improvement in various diversion technologies. 展开更多
关键词 fluid diversion Diverter Diverting agents Multi-stage fracturing Hydraulic fracturing Horizontal well
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Intermolecular interactions induced property improvement for clean fracturing fluid by deep eutectic solvents
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作者 Xiang-Yu Wang Ming-Wei Zhao +6 位作者 Xu-Hao Wang Peng Liu Meng-Yao Fan Teng Li Zhen-Feng Ma Ying-Jie Dai Cai-Li Dai 《Petroleum Science》 SCIE EI CAS CSCD 2023年第6期3540-3552,共13页
Fracturing fluid property play a critical role in developing unconventional reservoirs.Deep eutectic solvents(DESs)show fascinating potential for property improvement of clean fracturing fluids(CFFs)due to their low-p... Fracturing fluid property play a critical role in developing unconventional reservoirs.Deep eutectic solvents(DESs)show fascinating potential for property improvement of clean fracturing fluids(CFFs)due to their low-price,low-toxicity,chemical stability and flexible designability.In this work,DESs were synthesized by mixing hydrogen bond acceptors(HBAs)and a given hydrogen bond donor(HBD)to explore their underlying influence on CFF properties based on the intermolecular interactions.The hydrogen-bonding,van der Waals and electrostatic interactions between DES components and surfactants improved the CFF properties by promoting the arrangement of surfactants at interface and enhancing the micelle network strength.The HBD enhanced the resistance of CFF for Ca^(2+) due to coordination-bonding interaction.The DESs composed of choline chloride(ChCl)and malonic acid show great enhancement for surface,rheology,temperature resistance,salt tolerance,drag reduction,and gel-breaking performance of CFFs.The DESs also improved the gel-breaking CFF-oil interactions,increasing the imbibition efficiencies to 44.2%in 74 h.Adjusting HBAs can effectively strengthen the intermolecular interactions(e.g.,HBA-surfactant and HBD-surfactant interactions)to improve CFF properties.The DESs developed in this study provide a novel strategy to intensify CFF properties. 展开更多
关键词 Deep eutectic solvents(DESs) Clean fracturing fluids(CFFs) Intermolecular interactions Property improvement
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Temporal variations in geochemistry of hydraulic fracturing fluid and flowback water in a tight oil reservoir
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作者 Jie Tian Liang Wang +3 位作者 Li-Pin Ni Li-Wei Mou Shu-Te Su Mehdi Ostadhassan 《Petroleum Science》 SCIE EI CSCD 2023年第5期3013-3021,共9页
Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of t... Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64.Freshwater is used for fracturing,and HFF is obtained.The chemical and isotopic parameters(including the water type,total salinity,total dissolved solids(TDS),pH,concentrations of Na^(+),Cl^(-),Ba^(+),K^(+),Fe^(2+)+Fe^(3+),and CO_(3)^(2-),dD,and δ^(18)O)are experimentally obtained,and their variations with time are systematically analyzed based on the flowback water.The results show that the water type,Na/Cl ratio,total salinity,and TDS of the FPW change periodically primarily due to the HFF mixing with formation water,thus causing δD and δ^(18)O to deviate from the meteoric water line of Xinjiang.Because of watererock interaction(WRI),the concentrations of Fe^(2+)+Fe^(3+)and CO_(3)^(2-)of the FPW increase over time,with the solution pH becoming more alkaline.Furthermore,based on the significant changes observed in the geochemistry of the FPW,three separate time intervals of flowback time are identified:Stage Ⅰ(<10 days),where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI;Stage Ⅱ(10-37 days),where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened;and finally,Stage Ⅲ(>37 days),where the FPW is dominated by the chemistry of the formation water.The methodology implemented in this study can provide critical support for the source identification of formation water. 展开更多
关键词 Tight oil reservoirs ISOTOPE Flowback and produced water(FPW) Inorganic ions Hydraulic fracturing fluid(HFF)
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Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids 被引量:17
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作者 Hong-Kui Ge Liu Yang +4 位作者 Ying-Hao Shen Kai Ren Fan-Bao Meng Wen-Ming Ji Shan Wu 《Petroleum Science》 SCIE CAS CSCD 2015年第4期636-650,共15页
Spontaneous imbibition of water-based frac- turing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix... Spontaneous imbibition of water-based frac- turing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the frac- turing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KC1 solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most impor- tant factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The aver- age ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KC1 solution can inhibit clay absorption to reduce the imbibition capacity. 展开更多
关键词 Imbibition . Shale fracturing fluid Capillary pressure CLAY
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Investigation of influence factors on CO_(2) flowback characteristics and optimization of flowback parameters during CO_(2) dry fracturing in tight gas reservoirs
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作者 Xiao-Mei Zhou Lei Li +4 位作者 Yong-Quan Sun Ran Liu Ying-Chun Guo Yong-Mao Hao Yu-Liang Su 《Petroleum Science》 SCIE EI CAS CSCD 2023年第6期3553-3566,共14页
CO_(2) dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs,especially in water-scarce areas such as the Loess Plateau.The CO_(2) flowback efficiency is a critical factor that a... CO_(2) dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs,especially in water-scarce areas such as the Loess Plateau.The CO_(2) flowback efficiency is a critical factor that affects the final gas production effect.However,there have been few studies focusing on the flowback characteristics after CO_(2) dry fracturing.In this study,an extensive core-to-field scale study was conducted to investigate CO_(2) flowback characteristics and CH_(4) production behavior.Firstly,to investigate the impact of core properties and production conditions on CO_(2) flowback,a series of laboratory experiments at the core scale were conducted.Then,the key factors affecting the flowback were analyzed using the grey correlation method based on field data.Finally,taking the construction parameters of Well S60 as an example,a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs.The production parameters after CO_(2) dry fracturing were then optimized.Experimental results demonstrate that CO_(2) dry fracturing is more effective than slickwater fracturing,with a 9.2%increase in CH_(4) recovery.The increase in core permeability plays a positive role in improving CH_(4) production and CO_(2) flowback.The soaking process is mainly affected by CO_(2) diffusion,and the soaking time should be controlled within 12 h.Increasing the flowback pressure gradient results in a significant increase in both CH_(4) recovery and CO_(2) flowback efficiency.While,an increase in CO_(2) injection is not conducive to CH_(4) production and CO_(2) flowback.Based on the experimental and field data,the important factors affecting flowback and production were comprehensively and effectively discussed.The results show that permeability is the most important factor,followed by porosity and effective thickness.Considering flowback efficiency and the influence of proppant reflux,the injection volume should be the minimum volume that meets the requirements for generating fractures.The soaking time should be short which is 1 day in this study,and the optimal bottom hole flowback pressure should be set at 10 MPa.This study aims to improve the understanding of CO_(2) dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters. 展开更多
关键词 CO_(2)fracturing Tight gas reservoir fracturing fluid flowback Parameter optimization
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Investigation on microscopic invasion characteristics and retention mechanism of fracturing fluid in fractured porous media 被引量:2
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作者 Qi-An Da Chuan-Jin Yao +3 位作者 Xue Zhang Xiao-Pu Wang Xiao-Huan Qu Guang-Lun Lei 《Petroleum Science》 SCIE CAS CSCD 2022年第4期1745-1756,共12页
Reservoir damage caused by guar gum fracturing fluid and slick water seriously affects the subsequent oil and gas production. However, the invasion characteristics and retention mechanisms of fracturing fluids in the ... Reservoir damage caused by guar gum fracturing fluid and slick water seriously affects the subsequent oil and gas production. However, the invasion characteristics and retention mechanisms of fracturing fluids in the fracture-matrix zone are still unclear. In this work, a microscopic model reflecting the characteristics of the fracture-matrix zone was designed. Based on the microfluidic experimental method, the process of fracturing fluid invasion, flowback and retention in the fracture-matrix zone was investigated visually and characterized quantitatively. The factors and mechanisms affecting fracturing fluid retention in the fracture-matrix zone were analyzed and clarified. The results indicated that in the invasion process, the frontal swept range of slick water was larger than that of the guar gum fracturing fluid, and the oil displacement efficiency and damage rate were lower than those of the guar gum fracturing fluid under the same invasion pressure. With the increase in invasion pressure, the damage rate of slick water increased from 61.09% to 82.77%, and that of the guar gum fracturing fluid decreased from 93.45% to83.36%. Before subsequent oil production, the invaded fracturing fluid was mainly concentrated in the medium-high permeability area of the fracture-matrix zone. The main resistance of slick water was capillary force, while that of the guar fracturing fluid was mainly viscous resistance. The fracturing fluid retention was most serious in the low permeability region and the region near the end of the fracture.The experimental and numerical simulation results showed that increasing the production pressure difference could improve the velocity field distribution of the fracture-matrix zone, increase the flowback swept range and finally reduce the retention rate of the fracture fluid. The retention mechanisms of slick water in the fracture-matrix zone include emulsion retention and flow field retention, while those of the guar gum fracturing fluid include viscous retention and flow field retention. Emulsion retention is caused by capillary force and flow interception effect. Viscous retention is caused by the viscous resistance of polymer, while flow-field retention is caused by uneven distribution of flowback velocity. 展开更多
关键词 Microfluidic experiment Reservoir damage fracturing fluid fracture-matrix zone Retention mechanism
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Fracturing and Episodic Fluid Expulsion in Pressure Compartments 被引量:1
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作者 Mei Lianfu Department of Petroleum Geology, China University of Geosciences, Wuhan 430074 Wang C.Y. Department of Geology and Geophysics, University of California, Berkeley 94720 Cai Yongen Department of Geology, Peking University, Beijing 100871 《Journal of Earth Science》 SCIE CAS CSCD 1998年第2期32-36,共5页
The fracturing of the pressure compartments in sedimentary basins may not be caused completely by natural hydraulic fracturing. On the bases of fracture mechanics and numerical simulation, we consider that there are t... The fracturing of the pressure compartments in sedimentary basins may not be caused completely by natural hydraulic fracturing. On the bases of fracture mechanics and numerical simulation, we consider that there are two mechanisms concerning the fracturing of pressure compartments, which are as follows: (1) natural hydraulic fracturing of the sediments within pressure compartments, and (2) tensile fracturing due to tangential traction. When the fracture, formed in the sediments within pressure compartments due to hydraulic fracturing, arrives at the base of the seal, the intensely tangential tensile stresses are created and lead to the fracturing of the seal. After the seal fractured, the fluid escaped from the pressure compartments. In a shallow pressure compartment, the duration of fracture opening and fluid expulsion is about 10-20 years in a cycle. 展开更多
关键词 pressure compartments fracturing episodic fluid expulsion.
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