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In order to study the influence law of gas desorption accumulation and emission characteristics under hydraulic fracturing, this experiment uses coal-rock adsorption–desorption test equipment to carry out isothermal desorption tests of water-bearing coal under various stress paths. The experimental object is anthracite from Four Seasons Chun coal mine in Guizhou Province. In this experiment, the influence law of the desorption emission characteristics of coal under different stresses is analyzed. Research shows that the stress directly affects the gas desorption of coal and plays a decisive role in the gas desorption and emission characteristics of water-bearing coal in the stress-affected zone. Under equivalent gas adsorption of water-bearing coal, the total accumulated gas desorption displayed by coal increases with the increase in stress under certain conditions and the increase rate slows down with the time; coal samples differing in moisture content are subjected to various stress paths, leading to the difference in the total gas desorption. The total accumulated gas desorption displayed by coal with higher moisture content is generally smaller than that with lower moisture content. Through field observation, a zone with high accumulated gas desorption is formed in the stress-affected zone beyond the radius of effective fracture influence, generating an imbalance of gas desorption and emission. The study results are of theoretical and practical engineering significance for the prevention and control of stress-induced disasters and gas disasters in deep coal seams. [ABSTRACT FROM AUTHOR]

To understand the occurrence state of fracturing fluid in shale gas matrix-fracture system, an experimental method for evaluating fracturing fluid flow characteristics in matrix-fracture system was established. By using Nuclear Magnetic Resonance method, the flow characteristics of fracturing fluid were investigated from three processes of filtration, well shut-in and flowback. The T2 spectrum of fracturing fluid flow process and fracturing fluid saturation in matrix-fracture core model were clarified. The results demonstrate that the peak area of T2 spectra increases gradually during the filtration process, and the fracturing fluid quickly fills the fractures and matrix pores. During the well shut-in process, the fracturing fluid gradually flows from the fracture space to the matrix pores, and the signal of the matrix pores increases by 50.5%. During the flowback process, fracturing fluid flows out of the matrix and fracture. And when it reaches a stable state, the peak signal in the fracture decreases by 64.5% and the matrix signal reduces by 18.8%. The better the porosity and permeability characteristics of the core, the more likely the fracturing fluid is to stay in the formation and cannot be discharged. This paper would contribute to basic parameters for shale gas fracturing design and production strategy optimization. [ABSTRACT FROM AUTHOR]

The stress threshold of deep reservoir shale subjected to fracturing fluid immersion is an important factor affecting fracture initiation and propagation during fracturing. However, little information has been reported on the effect on shale of soaking at high temperature and high pressure (HTHP). In this study, immersion tests and triaxial compression tests were carried out at reservoir temperature and in-situ stress on the downhole cores with different mineral compositions. The characteristics of stress thresholds, i.e., crack initiation stress ( σ c i ), crack damage stress ( σ cd ), and peak deviator stress ( σ p ), of shale affected by the different times of soaking with low-viscosity fracturing fluid (a) and the different viscosity fracturing fluids (a, b, and c) were investigated. The results show that hydration at HTHP has a significant softening effect on the stress thresholds ( σ c i , σ cd , σ p ) of reservoir shale, but the softening rate varies for samples with different mineral compositions. The crack initiation stresses of quartz-rich and clay-rich shales treated with different soaking times and different soaking media remain almost unchanged in the range of 47 to 54% of the corresponding peak strength, while the crack initiation stresses of carbonate-rich shales are significantly affected. The ratio σ cd / σ p of quartz-rich shale is significantly affected by the different viscosity fracturing fluids (a, b) and the different times of soaking with low-viscosity fracturing fluid (a), while clay- and carbonate-rich shales are less affected. The results of this study can provide a reference for the fracturing design of deep shale gas development. [ABSTRACT FROM AUTHOR]

The strong stress interference and fluid competitive distribution result in the non-uniform propagation of multiple fractures during horizontal well multi-stage hydraulic fracturing (HWMHF). The uniform stimulation effect can be effectively improved by adjusting the injection rate and perforation scheme. In this work, a two-dimensional fluid–solid fully coupled multi-fracture propagation model is established to investigate the pattern of multi-fracture propagation and the flow distribution. The considering factors include the fluid injection rate, the perforation parameters, and the reservoir heterogeneity. The pipe element is developed to realize the free fluid distribution among multiple fractures. The results show that multiple fractures are more likely to initiate simultaneously and propagate uniformly with a higher fluid injection rate. The stress interference among multiple fractures can be balanced and the equilibrium propagation degree of multiple fractures can be greatly improved by reducing the perforation number. In the homogeneous reservoir, when the fluid injection rate is 12 m3/min and the perforation number per cluster is reduced to 10, the difference coefficient of fluid distribution can be reduced to 3.31%. In the heterogeneous reservoir, multiple perforation clusters with different tensile strengths can generate nearly uniform fractures by increasing the fluid injection rate and reducing the perforation number. When the fluid injection rate is 12 m3/min and the perforation number per cluster is 6, the difference coefficient of fluid distribution can be reduced to 3.26%. This work is of great significance in clarifying the propagation pattern and optimizing the fluid injection rate and the perforation number to improve the uniform propagation degree of multiple fractures. [ABSTRACT FROM AUTHOR]

CO2 miscible flooding is a great promising enhanced oil recovery (EOR) method. However, the loss of fracturing fluid in the formation causes water blocking that seriously impedes the realisation of CO2 miscible flooding. To solve this problem, a strategy of applying an oscillating electric field to promote CO2 breaking through water blocking and enhance the miscibility of CO2 and oil is proposed. The electric field with the frequency of 12 THz can maximise the breakthrough efficiency of water blocking, while the 16 THz electric field is most conducive to the miscibility of CO2 and oil. Under the 12 THz oscillating electric field, the prompt destruction of the local hydrogen bonds in water blocking results in the fastest breakthrough of water blocking. However, the expansion of water blocking hinders the miscibility of CO2 and oil to some extent. 16 THz oscillating electric field can induce the electric resonance of hydrogen bonds between water molecules, uniformly breaking hydrogen bonds to the greatest extent. Compared to that under the 12 THz electric field, the miscibility of CO2 and oil under the 16 THz electric field is enhanced due to the reduced expansion of water blocking. [ABSTRACT FROM AUTHOR]

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of China Surfactant Detergent & Cosmetics (2097-2806) is the property of China Surfactant Detergent & Cosmetics Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag. [ABSTRACT FROM AUTHOR]

Despite the high detection level of the Italian seismic network and the risk associated with its fault networks, Central‐Southern Italy has no unique geophysical model of the crust able to illuminate its complex tectonics. Here, we obtain seismic attenuation and scattering tomography models of this area; both reveal high attenuation and scattering anomalies characterizing the entire Apenninic Chain and related to its East‐ and West‐dipping extensional Quaternary tectonic alignments. Fault‐associated fractured zones become preferential ways for circulating and degassing high‐attenuation CO2‐bearing fluids. A previously undetected fluid source area is a high‐attenuation volume below the Matese complex, while a similar smaller anomaly supports a fluid source near L'Aquila. The most prominent low attenuation and scattering volumes reveal a locked aseismic zone corresponding to the Fucino‐Morrone‐Porrara fault systems, representing a zone of significant seismic hazard. Plain Language Summary: Geophysical methods are the most used tools for imaging the subsurface. Still, their resolution and reliability depend on the amount of good‐quality data and the sensitivity of the technique used for the target structures. Improvements in the seismic detection infrastructures of the last decade allow imaging zones characterized by sparse seismicity, like Central‐Southern Italy. Once combined with these data, new imaging techniques targeting attributes with higher sensitivity to stress and fluid saturation provide unprecedented resolution on tectonic interactions and fluid sources in this area. Here, we measured and mapped in 3D the energy lost by seismic waves during their propagation. Our results show a high‐attenuation volume elongated in the direction of the Apenninic Chain and particularly intense in Southern Italy, mapping fluid‐filled fracturing and a fluid source likely coinciding with the Matese area. The principal normal and reverse faults in the area control high‐attenuation zones. The most prominent low attenuation and scattering volume marked locked areas with low seismic energy release, suggesting them as the zones of stress accumulation. Key Points: Scattering and attenuation tomography image the tectonics of the Apennine Mountain Belt ChainHigh‐attenuation anomalies mark crustal sources of CO2 following major structural alignmentsA high‐attenuation/high‐scattering volume reveals an extended fluid source beneath the Matese Mountains [ABSTRACT FROM AUTHOR]

The main objective of the work is to analyse the areas of alteration susceptible to cracks in the test areas of the marble, travertine and andesite quarries in Romania, based on investigations using the resistivity method. The test areas chosen within the ERA-MIN project entitled "Artificial intelligence and combined survey techniques for the optimization of stone quarries" were in the Ruschita, Carpinis and Pietroasa quarries. The data were collected on equidistant profiles at 5-10m, the distance between the electrodes being 2m. The location of the profiles was chosen according to the size, position of the quarry, visible natural discontinuities and their orientation. The acquisition, processing and interpretation of resistivity data were performed with Super Sting R8/IP+64 system and Earth Imager software. After performing the interpretation of the resistivity electrometric tomography, it was possible to underline that the maximum resistivity was associated with unaltered areas, without fractures of circulated fluids. Also, the resistivity minima were associated with altered areas susceptible to deep fractures. These qualitative considerations were corroborated with information from other geophysical and geotechnical measurements as well as with direct information from quarry investigations. The resistivity information is a deliverable of the project that will be used in the future to complete a complex informational table that will serve to identify the optimal cutting directions in the stone blocks to increase the unaltered and uncracked volumes of the stone as well as, implicitly, the increase of their commercial value. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology was utilized to conduct high-pressure soaking tests on shale specimens treated with EM30+ + guar gum mixed water and CNI nano variable-viscosity slickwater, where various concentrations of a drag reducer were utilized. Additionally, the differences in porosity, permeability, mineral composition, and iron ion concentration before and after the measurements were compared, which were used to analyze the influence on the shale's microscopic pore structure. It features a reduction in the total pore volume after the interaction with the fracturing fluid, with the pore-throat damage degree, porosity damage degree, and permeability damage degree ranging from 0.63% to 5.62%, 1.51% to 6.84%, and 4.17% to 19.61%, respectively. Notably, EM30+ + guar gum mixed water exhibits heightened adsorption retention, alkaline dissolution, and precipitation compared to CNI nano variable-viscosity slickwater, rendering it more deleterious to shale. Moreover, higher concentrations of drag reducers, such as EM30+ or CNI-B, predominantly result in damage to the shale's micropores. Shale compositions characterized by lower content of quartz and elevated proportions of clay minerals and iron-bearing minerals showcase augmented mineral dissolution and precipitation, consequently intensifying the shale damage. The hydration expansion of mixed-layer illite/smectite profoundly diminishes the core permeability. Consequently, the mechanisms underpinning the damage inflicted on shale's microscopic pore structure primarily involve fracturing fluid adsorption and retention, mineral dissolution, and precipitation, such as clay minerals and iron-containing minerals. [ABSTRACT FROM AUTHOR]

To enrich the clean fracturing fluid system with high temperature resistance, a novel tetrameric cationic surfactant (TET) was developed and used as a thickener and mixed with different concentrations of sodium salicylate (NaSal) to obtain a new clean fracturing fluid. The flow curves, thixotropy, viscoelasticity, temperature resistance property, and proppant‐suspending capacity were further investigated. The rheological study showed that the Casson model could be used to accurately describe the flow curve of TET/NaSal micelle solutions and the addition of NaSal improved the thixotropy and viscoelasticity of surfactant solution. The optimal mass ratio of TET/NaSal solution was 5/1.5 wt%, and it had good proppant‐suspending capacity. What is more, the retained viscosity of TET/NaSal (5/1.5 wt%) solution was 52.27 mPa·s after shearing at 140°C and 100.0 s−1 for 65 min, which met industry requirements (viscosity > 20 mPa·s) of viscoelastic surfactant fracturing fluids. Moreover, the combination of 10 wt% TET aqueous solution with pH value of 8.51 and 2.6 wt% salicylic acid (HSal) suspension of the same mass significantly delayed micellar formation. The four‐parameter rheo‐kinetics model can be used to fit the viscosity curves of micellar formation, which provided the rheological basis for the study of delayed viscoelastic micellar formation. [ABSTRACT FROM AUTHOR]

[Display omitted] Worm-like micelles are susceptible to heating owing to the fast dynamic exchange of molecules between micelles. Inhibition of such exchange could afford robust worm-like micelles, which is expected to largely improve rheology properties at high temperatures. A cationic surfactant docosyl(trimethyl)azanium chloride (DCTAC) and a strongly hydrophobic organic counterion 3-hydroxy naphthalene-2-carboxylate (SHNC) were used for the worm-like micelles fabrication. The microstructure was characterized using cryogenic transmission electron microscopy and small-angle neutron scattering, and the interactions between DCTAC and SHNC were characterized using nuclear magnetic resonance spectroscopy. Rheometer was employed to measure the rheological properties of the solution. SHNC/DCTAC at the molar ration of 1:2 forms ultra-stable worm-like micelles, whose viscosity remain stable at temperature up to 130 °C. SHNC is found to strongly adsorbs on DCTAC micelle with the orientation on the surface of micelle, keeping the naphthalene backbone entire penetration into the palisade layer while both carboxylic and hydroxyl groups protrude out of the micelle. With temperature increasing, this adsorption further strengthens, resulting in the growth contour length and accompanying the enhancement of rheological properties. One SHNC molecule and two DCTAC molecules are speculated to form a stable complex via multiple interactions including hydrophobic, cationic-π, and π-π interactions, which decreases the dynamic exchange of them between micelles. These findings are helpful to understand surfactant aggregates stability and assist the development of novel stable supramolecular nanostructures. Additionally, the excellent thermal stability of this worm-like micellar fluid makes it a potential high-temperature resistant clean fracturing fluid for deep oil reservoirs. [ABSTRACT FROM AUTHOR]

In this study, nuclear magnetic resonance and computed tomography scanning were used to analyze the production law and displacement mechanism of Jimusaer continental shale oil during CO2 huff 'n' puff, and the optimal parameters were determined. The results indicated that CO2 huff 'n' puff mainly produces crude oil in pore throats with 0.1–1 μm radii, while crude oil in pore throats with radii below 0.1 μm cannot be produced. Multiple CO2 huff 'n' puff cycles can connect fluids in fractures with fluids in large–medium pore throats, eliminate fracture effects on the oil recovery factor, and achieve coefficient development of both fractured and unfractured shales. In the CO2 huff 'n' puff process, core pressure change could be divided into three stages of injection–holding–depletion, and the oil displacement mode was the piston type. The study of huff 'n' puff parameters revealed that huff 'n' puff cycles and injection pressure have a great influence on the CO2 huff 'n' puff efficiency, while the injection timing and soaking time imposed relatively small effects. For continental shale in the Jimusaer Sag, the optimal CO2 huff 'n' puff parameters are five cycles, 4‐MPa injection timing, 25‐MPa injection pressure, and 12‐h soaking time. [ABSTRACT FROM AUTHOR]

China's argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize fracturing parameters. The second problem is that there are a lot of natural fractures in the argillaceous limestone reservoir, which leads to a lot of fracturing fluid loss. The third problem is that the closure pressure of the argillaceous limestone reservoir is high, and the conductivity of fractures decreases rapidly under high closure pressure. The last problem is that the fracture shape of the argillaceous limestone reservoir is complex, and the law of proppant migration is unclear. The main research methods in this paper include reservoir numerical simulation, fluid-loss-reducer performance evaluation, flow conductivity tests and proppant migration visualization. To solve the above problems, this paper establishes the fracturing productivity prediction model of complex lithology reservoirs and defines the optimal hydraulic fracturing parameters of the argillous limestone reservoir in the Sichuan Basin. The 70/140 mesh ceramide was selected as the fluid loss additive after an evaluation of the sealing properties of different mesh ceramides. At the same time, the hydraulic fracture conductivity test is carried out in this paper, and it is confirmed that the fracture conductivity of 70/140 mesh and 40/70 mesh composite particle-size ceramics mixed according to the mass ratio of 5:5 is the highest. When the closure pressure is 40 MPa, the conductivity of a mixture of 70/140 mesh ceramic and 40/70 mesh ceramic is 35.6% higher than that of a mixture of 70/140 mesh ceramic and 30/50 mesh ceramic. The proppant migration visualization device is used to evaluate the morphology of the sand dike formed by the ceramsite, and it is clear that the shape of the sand dike is the best when the mass ratio of 70/140 mesh ceramsite and 40/70 mesh ceramsite is 6:4. The research results achieved a good stimulation effect in the SC1 well. The daily oil production of the SC1 well is 20 t, and the monitoring results of the wide-area electromagnetic method show that the fracturing fracture length of the SC1 well is up to 129 m. [ABSTRACT FROM AUTHOR]

To study the effect of the non-uniform distribution of minerals on the development of microcracks within the rock during hydraulic fracturing, a novel numerical model considering multiple random mineral distributions was designed. The model investigated the impacts of mineral grain size, composition, and spatial arrangement on fracture initiation and propagation. The results indicate that the presence of the hard-phase mineral quartz can alter the propagation path of fractures, and increase the width of hydraulic fractures. In coarse-grained granite, the range of crack deflection is maximized, while in medium-grained granite, it is more prone to forming convoluted elongated cracks. A higher quartz content in granite further contributes to the formation of complex crack networks. Simultaneously, the evolution of granite fractures and variations in breakdown pressure in heterogeneous granite were investigated, considering the influence of core parameters such as fluid injection rate, fracturing fluid viscosity, and horizontal stress difference. The research reveals that a high injection rate promotes straight-line fracture expansion. Moreover, modest fluctuations in fracturing fluid viscosity have minimal effects on fracture morphology. When the fracture development avoids quartz, under the influence of high horizontal stress differential, it clearly turns toward the direction of the maximum principal stress. This study can offer insights into innovative and optimized deep reservoir fracturing techniques. [ABSTRACT FROM AUTHOR]

The existing pump-stopping pressure drop models for the hydraulic fracturing operation of tight oil reservoirs only consider the main hydraulic fracture and the single-phase flow of fracturing fluid. In this paper, a new pump-stopping pressure drop model for fracturing operation based on coupling calculation of the secondary fracture and oil-water two-phase flow is proposed. The physical model includes the horizontal wellbore, the fracture network and the tight oil reservoir. Through the numerical simulation and calculation, the wellbore afterflow performance, the crossflow performance between the main hydraulic fracture and the secondary fracture, the fracturing fluid leakoff and the oil-water replacement after termination of pumping are obtained. The pressure drop characteristic curve is drawn out by the bottom-hole flow pressure calculated through the numerical simulation, and a series of analyses are carried out on the calculated pressure drop curve, which is helpful to diagnose the -oil-water two-phase flow state and the fracture closure performance under the control of the fracture network after hydraulic fracturing pumping. Finally, taking a multi-stage fractured horizontal well in a tight oil reservoir in the Junggar basin, China as an example, the pump-stopping pressure drop data of each stage after hydraulic fracturing are analyzed. Through the history fitting of the pressure drop characteristic curve, the key parameters such as fracture network parameters, which include the half-length of main hydraulic fracture, the conductivity of main hydraulic fracture and the density of secondary fracture, the fracture closure pressure are obtained by inversion, thus, the hydraulic fracturing effect of fractured horizontal well in tight oil reservoirs is further quantified. [ABSTRACT FROM AUTHOR]

This study investigates a new type of high-performance coated sand as a petroleum fracturing proppant material. Modified quartz sand was coated with a layer of low-density resin to reduce the overall density of the proppant, thereby improving the suspension of the proppant in the fracturing fluid. Resins play an important role in the preparation of coated sand fracturing proppants. The mechanism of sand formation was studied by examining the phase composition and microstructure of the coated sand proppant. The results demonstrate that when the polyimide resin content is 6% and the curing temperature is 180 °C, the proppant exhibited the best performance with an apparent density of 1.592 g/cm3 and a breakage ratio of only 3.22% under 55.2 MPa. Compared with the widely used epoxy resin-coated support agent and phenolic resin-coated support agent in the early stage, their crushing rate decreased by 5% and their acid solubility decreased by 2%. Hence, this study is worthy of attention. [ABSTRACT FROM AUTHOR]

A recyclable biogum thickener was developed and employed as the main agent to compound a fracturing fluid system in order to address the issue of the problematic recovery of fracturing fluid system. By using infrared (IR), nuclear magnetic resonance (NMR), X‐ray diffraction (XRD), and scanning electron microscopy (SEM), the physical characteristics and microstructure were examined. By using a rheometer, dynamic filtration loss, and an acid‐etching fracture conductivity device, respectively, the system's temperature and shear resistance, dynamic filtration loss, and fracture conductivity damage were studied. The system's gum‐breaking performance, formation water compatibility, and anti‐expansion performance were then measured in accordance with standards. As a result of shearing at 170 s−1 and 120°C for 2 h, the 4% biogum system's performance outperformed the other two systems in every way, according to the experimental findings. Its viscosity could also exceed 70 mPa · s. After breaking, the solution had a viscosity of 2.5 mPa · s, which was very compatible with the formation water. The system has a 90% anti‐swelling rate, a filtration loss coefficient of 5.14 × 10−5, strong infiltration ability, and negligible formation damage. The biogum system's recovery rate after field application is discovered to be around 50%. [ABSTRACT FROM AUTHOR]

A novel trimeric cationic surfactant (TEC) has been investigated to use as a hydraulic fracturing fluid thickener with thermal stability. TEC was synthesized with trimethylolpropane triglycidyl ether, erucamidopropyl dimethylamine and hydrochloric acid at 50.0 °C for 7.0 h. The product was compounded with potassium chloride (KCl) for an optimized formulation to form viscoelastic micelles with high-temperature resistance. The apparent viscosity of 5.0 wt%TEC/1.2 wt%KCl fluid remains 23.1 mPa·s after shearing for 90.0 min at 160.0 °C and 100.0 s−1. Three-dimensional (3 D) networks formed by entangled worm-like micelles (WLMs) were observed by an environmental scanning electron microscope. The TEC/KCl solution has a simple formulation and excellent rheological properties, which enriches the viscoelastic surfactant (VES) fracturing fluid class with high-temperature resistance. [ABSTRACT FROM AUTHOR]

In this work, efficient Fenton strategy have been proposed for degradation of shale gas fracturing flow-back wastewater using the spherical Fe/Al2O3 supported catalyst. Prior to actual fracturing fluid treatment, the typical model wastewaters such as p-nitrophenol and polyacrylamide were employed to evaluate the catalytic properties of prepared catalyst, and then Fenton treatment of the shale gas fracturing flow-back wastewater was performed on the self-assembled catalytic degradation reactor for continuous flow purification. Results showed that under the conditions of 0.25 mol L−1 impregnating concentration, pH 4, 50 g L−1 catalyst and 0.75 mL L−1 30% H2O2, the removal efficiency of p-nitrophenol and polyacrylamide reached 74% and 61%, respectively, while the COD removal of fracturing flow-back fluid was approximately 48% with the residual 88 mg L−1 COD, meeting the emission standards of the integrated wastewater discharge standard (GB 8978-1996, COD < 100 mg L−1). This work offers new alternatives for Fenton treatment of real wastewater by efficient and low-cost supported catalysts. [ABSTRACT FROM AUTHOR]

As a potential reservoir stimulation fracturing fluid, carbon dioxide (CO2) offers significant advantages in enhancing the recovery of hydrocarbon resources and reducing reservoir damage. Sparse sandstone reservoirs are often plagued by problems such as low recovery rates and severe reservoir damage, necessitating stimulation to improve flow capacity. However, studies on liquid CO2 fracturing tests in sparse sandstones are scarce. A combination of experimental and numerical methods is used to investigate the liquid CO2 fracturing mechanism and its applicability in sparse sandstone. The injection pressure and fracture morphology of water and liquid CO2 fracturing tests in sparse sandstones are analyzed and the influence of the permeation effect on the fracturing mechanism is explored. The applicability of liquid CO2 fracturing in sparse sandstone under different formation stress is investigated by numerical simulation. It is obtained that the breakdown pressure of liquid CO2 fracturing in sparse sandstone is lower, and the activation of interlayer can form a complicated fracture network. Liquid CO2 fracturing has a larger permeation effect, which leads to a lower pressurization rate and severely affects fracturing efficiency. Numerical simulation results demonstrate that the permeation effect descends significantly with formation stress increasing, especially when formation stress reaches 12/17 MPa, and the damage domain can be effectively concentrated. Therefore, when the formation stress reservoir depth is more than 600 m, liquid CO2 fracturing can be preliminarily used in sparse sandstone reservoir stimulation. The results of the study can guide the optimization of the field-scale fracturing treatment. Highlights: Liquid CO2 fracturing can significantly reduce breakdown pressure and form a complicated fracture network. The larger permeation volume of liquid CO2 fracturing in sparse sandstone decreases its fracturing efficiency. Increased formation stress significantly reduces the permeation effect and facilitates liquid CO2 fracturing applicability in sparse sandstone. [ABSTRACT FROM AUTHOR]

In petroleum exploration, cellulose derivatives such as carboxymethylcellulose (CMC) are frequently used in drilling, cementing and fracturing fluids. However, under extreme drilling conditions, these additives have limited performance. In this regard, cellulose nanocrystals particles (CNCs) which are also derived from cellulose material are a suitable candidate due to their shear thinning rheology and thixotropy properties, even at low concentrations, among so many properties thanks to their crystalline structure and their nanometric dimensions. In this work, hydrolyzed fibers from industrial cotton are acetylated using acetic anhydride and sulfuric acid as catalysts, with the aim to modify surface properties of the obtained CNCs without changing their fiber structure and morphology. FTIR analysis pointed out the acetylation success of the obtained nanocrystals whose dimensions were found to be unaltered by the modification process. SEM images of cotton nanocrystal indicate that CNCc surface modification preserves the nanoscale dimensions of the nanoparticles. Also, TGA analysis showed thermal stability for the acetylated CNCc. [ABSTRACT FROM AUTHOR]

In this study, a salt-resistant hydrophobic association polymer (PZDY) was synthesized from acrylamide, octadecyl dimethylallyl ammonium chloride, and decane polyoxyethylene ether acrylate by aqueous polymerization. Infrared spectroscopy, fluorescence spectroscopy, scanning electron microscopy, and other characterization methods were used to study its properties and the rheological properties of the PZDY solution were analyzed. The results showed that when concentration of NaCl is less than 5 wt% and that of CaCl2 is less than 1 wt%, the viscosity of 0.4 wt% PZDY increased with an increase of the salt concentration. When the salt concentration continued to increase, the PZDY viscosity gradually decreased. Investigation of the rheological behaviors showed that the 0.6 wt% PZDY in the 5 wt% NaCl and 1 wt% CaCl2 solution could withstand temperatures up to 180 °C after being sheared for 2500 s at 170 s−1 and its viscosity exceeded 50 mPa·s. Moreover, the viscosity of the 0.6 wt% PZDY in 5 wt% NaCl increased from 104 to 205 mPa·s and that in 1 wt% CaCl2 increased from 110 to 157 mPa·s at a shear rate of 170 s–1, at 180 °C, and a shear time of less than 500 s. Meanwhile, scanning electron microscope (SEM) results showed that the salt addition enhanced the quasi-spatial network structure, with closer clustering of PZDY molecules in the NaCl solution than in the CaCl2 solution. The storage modulus (G′) and loss modulus (G″) increased with the increase of the PZDY concentration. Therefore, PZDY can be used to improve the heat and shear resistance of fracturing fluids and enhance oil recovery. [ABSTRACT FROM AUTHOR]

In the context of tight sandstone reservoirs in the Ordos Basin characterized by compact and heterogeneous rock formations, conventional fracturing techniques yield monolithic fracture shapes, rendering 3D reservoir reconstruction unattainable. This study investigates the principles governing balanced initiation and propagation of fractures in multi-cluster fracturing within unconventional fracturing technology. Employing a large-scale true triaxial simulation experiment system, we utilize the dimensional analysis method (p theorem) to design a physical simulation experiment similarity criterion. Through various experimental adjustments involving proportioning, curing, and mechanical testing, we generate an artificially cured rock mass with mechanical parameters akin to the target layer. The rock mass is maintained at a size of 30 cm × 30 cm × 30 cm. Systematic physical simulation experiments on unconventional volume fracturing are carried out using the 30 cm-sized dense sandstone outcrop rock mass. Taking the conventional fracturing technology as a reference and manipulating experimental conditions and design parameters, we simulate the non-equilibrium initiation and extension behaviors of fracturing fractures under five unconventional volume fracturing technologies, namely hydraulic pulse pretreatment, temporary plugging between clusters, flow-limiting method, cyclic loading and unloading, and pulse intermittent fracturing. Through this, we elucidate the non-equilibrium initiation and extension laws governing multi-cluster fractures. Comparative analysis with conventional fracturing, known for inducing stress interference on fractures and inhibiting their expansion, revels that the five unconventional volume fracturing techniques mitigate stress interference in multi-cluster fracturing. This promotes uniform fracture initiation and expansion, facilitating the creation of complex fractures and larger reconstructed volumes. Among these techniques, intercluster block fracturing stands out for its exceptional ability to generate complex fracture networks. The research culminates in the development and refinement of a balanced fracture and extension control technique tailored for multiple cluster fractures in bulk fracturing. This technique significantly contributes to enhancing the degree of 3D reconstruction achievable in unconventional tight oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

To investigate the coupling effect of in situ stress and fluid pore pressure and the propagation law of damaged area during hydraulic fracturing and gas fracturing in heterogeneous fractured reservoirs, according to the effective stress principle and the smooth Rankine stress criterion, this paper establishes a coupled fluid–solid‐damage mathematical model of heterogeneous rock layers and carries out numerical simulations on the characteristic field changes of rock layers under water and nitrogen fracturing. The results show that the continuous injection of nitrogen or water can cause an increase in pore pressure in natural fractures and rock matrices, leading to rock damage and an increase in porosity. Under the same parameters, the damage area and length of the rock mass during nitrogen fracturing are larger than those of hydraulic fracturing, and the changes in pore pressure, permeability, and porosity are consistent with the damage area. The pore pressure near the connected natural fractures is relatively high, resulting in tensile strain; the pore pressure at isolated fractures is relatively low, and some even produce compressive strain. During nitrogen fracturing, the damage evolution is less affected by the in situ stress and the matrix permeability, while hydraulic fracturing is more affected by them. The damage area is the smallest when the horizontal in situ stress is equal. When the initial permeability of the matrix is low, the damaged area mainly follows the natural fractures and is distributed in a strip shape. As the permeability of the matrix increases, the fracturing fluid can enter the matrix, and the damaged area is in the shape of a block. [ABSTRACT FROM AUTHOR]

To study the effect of fracture morphology and in situ stress on the seepage behavior of rough fractures, hydraulic–mechanical experiments with different confining stresses, pore pressures and fracture geometry were carried out. The dimensionless parameter non-Darcy coefficient factor K and K-based critical Reynolds number model (KCRN) was proposed to characterize the behavior of rough-wall fracture and fluid seepage. The results show that the seepage flow of rough-wall fracture can be well described by Forchheimer equation. As the confining pressure increases from 1 to 31 MPa, the two walls of the rough fracture are compressed, and the fluid flow capacity is weakened, resulting in an increase of 2–3 orders of magnitude in Forchheimer viscosity coefficient A. Also affected by the increase in the confining pressure, the contact area between the two walls of the rough fracture increases, which makes the fluid channel become curved, increases the dissipation of water pressure in the inertial process and causes the inertial term coefficient B to increase by 2–3 orders of magnitude in general. In the whole range of test confining pressure (1 MPa–31 MPa), the flow state of rough fracture fluid is divided into zones based on the critical Reynolds number. The average hydraulic aperture decreases with the increase in the confining pressure, which can be perfectly fitted by hyperbolic function. The calculated critical Reynolds number of six rough fracture samples varies from 0.0196 to 1.0424. According to the experimental data, the K-based critical Reynolds number model (KCRN) is validated, and the validation results prove the accuracy and reliability of the model. [ABSTRACT FROM AUTHOR]

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Hydraulic fracturing plays a crucial role in enhancing reserves and production of unconventional oil and gas resources. Injecting fracturing fluids into the ground to improve reservoirs also introduces the risk of inducing earthquakes; thus, monitoring the migration of these fluids is crucial. The microseismic positioning method determines the fracturing fluid by locating microseismic events generated by the fractured rock strata; however, this method is susceptible to errors. Low-resistivity subsurface fluids can directly change electromagnetic field signals, making the electromagnetic method a technically advantageous approach for monitoring the migration of hydraulic fracturing fluids. The monitoring test data of Well Eyangye-2HF show that the time-lapse controlled-source electromagnetic (CSEM) method is suitable for hydraulic fracturing and has good monitoring effects. The results of CSEM method can also compensate for deficiencies in microseismic monitoring. The electric field (Ex) observed using the CSEM method can directly predict the distribution edge of the fracturing fluid, and the anomalous zone of the Ex rate of change is consistent with the fracturing-fluid injection parameters and microseismic monitoring results. The analysis of field data and forward simulation, based on electrical logging results, led to the conclusion that hydraulic fracturing operations can cause changes in the resistivity of the target layer and surrounding strata. These changes are attributed to the synergistic effects of formation stress, temperature, and the fracturing fluid. The electric-field changes observed using the CSEM method may be caused by multiple factors; however, use of time-lapse CSEM for monitoring hydraulic fracturing is still feasible. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Steam-assisted gravity oil drainage (SAGD flooding) is a cutting-edge technology for the development of oils which is gradually replacing steam huff and puff and is being used more and more widely. Low-permeability interlayers are generally developed in oil reservoirs in China, which may shield the migration of steam, oil and gas. Targeted acidizing fracturing was proposed to break through the low-permeability interlayers, and hence, the problem that the hindrance to the expansion of the steam chamber led to heat loss and seriously affected the development effect could be solved. A typical kind of well with SAGD flooding actually applied in China, Shuyi District of Liaohe Oilfield, was taken as the example for studying the optimization of crack parameters. Based on the study of reservoir sensitivity characteristics in this well, the formulations of working fluids for targeted acidizing fracturing were developed by optimizing the weight percentages of main acid solution and additives. The formula of '4% hydrochloric acid + 2% polyphosphoric acid + 5% fluoroboric acid + 4% acetic acid' could be used as the acidizing fracturing working fluid for typical blocks of the Shuyi District of Liaohe Oilfield, which can increase the permeability of the natural core by 40.19–57.06%. Studies on targeted acidizing fracturing are beneficial for enhancing the oil recovery of oil reservoirs. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an indispensable technology for the development of shale oil and shale gas. Knowing the changes in the rock mechanical properties and failure modes during hydraulic fracturing is the key to improving the efficiency of hydraulic fracturing. Based on experiments and simulations, it can be concluded that the injection of fracturing fluid in the hydraulic fracturing caused deformation of the fracture surface, and the rock mechanical properties experienced degradation with a maximum reduction in the rock mechanical properties of 44.24%. As indicated in the experiments, the displacement of the measurement point was decreased with the distance increase between the injection point and the measurement point. According to the numerical simulations, tensile failure is the main failure mode in hydraulic fracturing, but the percentage of shear failure had an obvious increase with the increase in distance between the injection point and the measurement point. Comparing DDS #1 and DDS #5, the DDS #5 measurement point was farther away from the injection point, and the average percentage of shear failure increased from 21.94 to 52.72%. Meanwhile, the increase in the branch fractures also caused shear failure to occur. Comparing Sample 1 and Sample 3, in Sample 3, which had more branch fractures, the average percentage of shear failure increased from 33.12 to 37.58%. Due to the porous medium of the reservoir rock, the enormous pressure generated during the injection of fracturing fluid caused significant deformation of the fracture surface, leading to the tensile failure of the rock. The displacement of the fracture surface caused by the fracturing fluid injection also led to the deformation of the pore throat structure; thus, the shear failure increased when the measurement point was away from the injection point. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is vital in recovering hydrocarbons from oil and gas reservoirs. It involves injecting a fluid under high pressure into reservoir rock. A significant part of fracturing fluids is the addition of polymers that become gels or gel-like under reservoir conditions. Polymers are employed as viscosifiers and friction reducers to provide proppants in fracturing fluids as a transport medium. There are numerous systems for fracturing fluids based on macromolecules. The employment of natural and man-made linear polymers, and also, to a lesser extent, synthetic hyperbranched polymers, as additives in fracturing fluids in the past one to two decades has shown great promise in enhancing the stability of fracturing fluids under various challenging reservoir conditions. Modern innovations demonstrate the importance of developing chemical structures and properties to improve performance. Key challenges include maintaining viscosity under reservoir conditions and achieving suitable shear-thinning behavior. The physical architecture of macromolecules and novel crosslinking processes are essential in addressing these issues. The effect of macromolecule interactions on reservoir conditions is very critical in regard to efficient fluid qualities and successful fracturing operations. In future, there is the potential for ongoing studies to produce specialized macromolecular solutions for increased efficiency and sustainability in oil and gas applications.

We present a series of controlled fluid injection experiments in the laboratory on a pre‐stressed natural rough fracture with a high initial permeability (∼10−13 m2) in granite using different fluid pressurization rates. Our results show that fluid injection on a fracture with a slight velocity‐strengthening frictional behavior exhibits dilatant slow slip in association with a permeability increase up to ∼41 times attained at the maximum slip velocity of 0.085 mm/s for the highest‐rate injection case. Under these conditions, the slip velocity‐dependent change in hydraulic aperture is a dominant process to explain the transient evolution of fracture permeability, which is modulated by fluid pressurization rate and fracture surface asperities. This leads to the conclusion that permeability evolution can be engineered for subsurface geoenergy applications by controlling the fluid pressurization rate on slowly slipping fractures. Plain Language Summary: Understanding the evolution of fracture permeability during hydraulic stimulation of subsurface reservoirs is the key to characterizing fluid transport and formulating strategies to limit induced seismicity. Accordingly, there is a significant interest in deciphering how the fluid pressurization rate, a constitutive operational parameter during injection, influences the transient permeability change during fracture slip. We conducted a series of experiments in the laboratory using different fluid pressurization rates on a natural rough fracture in granite under a pre‐stressed state. The fracture had a high initial permeability. Our findings show that when fluid is injected into a fracture with a slight velocity‐strengthening frictional behavior, it causes slow slipping with significant permeability enhancement. The change in hydraulic aperture caused by slip velocity is the main reason for the temporary change in permeability, and this effect is modulated by fluid pressurization rate and fracture surface irregularities. Our results suggest that we can modulate the permeability of subsurface geoenergy reservoirs by controlling the fluid pressurization rate on slowly slipping fractures. Key Points: We conducted fluid injection experiments on a pre‐stressed natural rough fracture in granite at different pressurization ratesThe velocity‐strengthening fracture exhibits slow slip accompanied by a significant increase in permeability during fluid injectionTransient fracture permeability is controlled by injection‐induced slip velocity, modulated by pressurization rate and surface asperities [ABSTRACT FROM AUTHOR]

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Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Water‐based fracturing fluids are widely used in the development of tight, low‐permeability unconventional oil and gas fields, where the crosslinking agent component can thicken the low‐viscosity, high‐flowability base fluid to ensure sufficient proppant is transported from the wellbore to the tip of the fracture and generate the required net pressure to support the fracture. Zirconium crosslinking agents are widely used due to their good stability and high shear resistance. In the paper, glycerin, zirconium chloride, lactic acid, sodium hydroxide, and water were reacted at a molar ratio of 7:1:3:4:98 and a temperature of 80°C for 5 h; Using triethanolamine, zirconium chloride, lactic acid, and water as raw materials, the molar ratio of 4:1:3:98, reaction at 80°C for 5 h, and then zirconium lactate crosslinker and triethanolamine zirconium lactate crosslinker were synthesized respectively, which were incorporated into a newly designed self‐generating acid temperature‐controlled crosslinking system to crosslink salt‐resistant cleaning fracturing fluids mainly composed of sodium carboxymethyl cellulose, achieving delayed crosslinking of the fracturing fluid in different temperature formations. The strong crosslinking temperature range of glycerol‐lactic acid zirconium and the rheological properties of triethanolamine zirconium lactate gel and zirconium lactate gel in the system were tested. The viscosity of triethanolamine zirconium lactate gel and zirconium lactate gel were 88.86 and 94.69 mPa·s, respectively, at the shear rate of 300 s−1, and the viscosity remained above 200 mPa·s at the shear rate of 170 s−1, 60°C for 1 h. These figures far exceed the gels formed by commercially purchased zirconate. This system can make glycerol lactic achouid zirconium crosslinking agents undergo strong crosslinking at 40–65°C and triethanolamine lactic acid zirconium undergo strong crosslinking at 55–75°C. It has significant implications for the delayed crosslinking effect of massive fracturing operations. [ABSTRACT FROM AUTHOR]

Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid. [ABSTRACT FROM AUTHOR]

Tight gas belongs to unconventional gas reservoirs, and to obtain high gas production, it needs to be fractured and reformed. After the construction is completed, a large amount of flowback fluid is produced. In order to reduce the cost of flowback fluid treatment and avoid environmental pollution, a slippery water system with flowback fluid is usually used on the site of hydraulic fracturing. Almost all flowback fluids contain high‐order cations such as calcium ions, magnesium ions, iron ions, and a large amount of suspended solids. Some flowback fluids contain incomplete gel‐breaking micelles and unseparated condensate oil. The performance of the viscosity‐reducing and slippery water system with flowback fluid as the base fluid is poor, usually manifested as low viscosity of the slippery water, low friction reduction rate, and high formation damage. To study the effect of tight gas fracturing flowback fluid on the performance of modified polyacrylamide viscosity‐reducing and slippery water system, this paper found through cryo‐electron microscopy scanning experiments that the flowback fluid made the modified polyacrylamide molecular chain unable to form a complex network structure and showed the phenomenon of reduced strength and aggregation. The effects of mineralization degree, calcium and magnesium ions, divalent and trivalent iron ions, suspended solids, pH value, and oil content on the viscosity, friction reduction performance, and rock damage of the viscosity‐reducing and slippery water system were analyzed experimentally. It was found that the viscosity of the viscosity‐reducing and slippery water system was mainly affected by divalent iron ions, calcium and magnesium ions and other divalent cations; the friction reduction rate was mainly affected by the content of suspended solids and oil content; and the rock damage was mainly affected by the pH value and the content of suspended solids. Based on this, recommended parameters for reusing tight gas fracturing flowback fluid are given to guide the smooth progress of hydraulic fracturing construction on‐site. [ABSTRACT FROM AUTHOR]

Using 1,8‐dihydroxynaphthalene, thionyl chloride and long‐chain tertiary amine as the main raw materials, a facile preparation method and formulation of a rigid double‐tailed surfactant for clean fracturing fluid were developed. The temperature resistance test and the determination of hydrogen spectrum reveal that the clean fracturing fluid with the prepared surfactant as thickener has excellent salt and temperature resistance. The shear viscosity of the best product at 120°C and 170 s−1 is not less than 65 mPa s, which meets the requirements of 25 mPa s for the field construction of clean fracturing fluid. [ABSTRACT FROM AUTHOR]

The main agent of clean fracturing fluid, cationic quaternary ammonium salt surfactant, is difficult to degrade in natural conditions because of its long alkyl chain. In this study, a biodegradable amphoteric surfactant, stearate sulfobetaine (SESB), was synthesized by esterification of long‐chain stearic acid and N,N‐dimethyl ethanolamine followed by quaternization to serve as the main agent of clean fracturing fluid. The structure of the synthetic degradable surfactant was verified by infrared and 1H‐nuclear magnetic resonance spectroscopies. In addition, a series of indoor performance evaluations were carried out, including shear resistance, viscoelasticity, sand carrying capacity, and gel‐breaking performance. A series of experimental evaluations showed that the clean fracturing fluid prepared with 2% SESB and 0.4% EDTA‐4Na had an excellent comprehensive performance. The apparent viscosity was higher than 50 mPa s at 80°C for a shear rate of 170 s−1. It has good heat and shear resistance performance. In addition, the system processed high shear stability and recovery at room temperature. According to the viscoelastic test, the system mainly relies on elasticity to carry sand. The static settling velocity of sand was 0.042 mm/s under high‐temperature conditions of 95°C. [ABSTRACT FROM AUTHOR]

The dominant fracture can be effectively plugged by injecting self-degradable diverters during temporary plugging fracturing. The subsequent fracturing fluids can divert into the poor fractures. The fracture complexity can be enlarged and the well production can be enhanced. This study established a new diverter temporary plugging evaluation system and carried out 23 groups of temporary plugging experiments to investigate the plugging characteristics of diverters within three-dimensional (3D) hydro-fractures. Experimental results show that (1) the formation process of a temporary plugged zone is determined by the bridging capability of the most significant particulates; (2) the tight plugged zone can undergo diverter attachment, bridging, filling, and compaction or diverter bridging, filling, and compaction; (3) diverters are most likely to plug distorted fractures, followed by inclined-flat fractures, and then axial/transverse-flat fractures due to the varying widths of hydro-fractures; (4) pure fibers can plug hydro-fractures when the fracture width is less than 1.5 mm, and the difference in the diameter of bridging particulates and the fracture width should be less than 1.5 mm when the fracture width exceeds 2.5 mm. Meanwhile, this study investigates the optimal temporary plugging agent formulations for different fracture widths based on economic factors and operational conditions, providing on-site recommendations. [ABSTRACT FROM AUTHOR]

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Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)