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Viscoelastic surfactants (VESs) are critical components of water-based fracturing fluids. However, the challenges related to the large volumes and complex disposal of flowback fluids from conventional VES fracturing fluids remain unresolved. Accordingly, a multifunctional small molecule surfactant gel was successfully prepared in this study. This system exhibits the capacity of in situ gel-breaking and converting it into an oil displacement agent, thus achieving the goal of no fluid return. The gel was composed of erucic acid amidopropyl betaine (EAPB), oleic acid amidopropyl betaine (OAPB), and a thickening agent, and the system was referred to as EOO. On the basis of this gel system, a series of performance parameters have been evaluated through extensive experiments. The research results demonstrated that this gel exhibits good stability, viscoelasticity, sand-carrying capacity, and remarkable self-repairing ability at high shear rates. Additionally, the gel achieves ultra-low interfacial tension and wetting reversal characteristics, both of which are conducive to enhanced oil recovery. Oil displacement and profile control of the gel were evaluated using single and parallel core flooding experiments. The results indicated that the EOO gel increased injection pressure in high-permeability cores and mobilized residual oil in low-permeability cores, thereby expanding the swept volume and enhancing recovery. The small molecule gel developed in this study which can be converted in situ into an oil displacement agent is a candidate for enhanced oil recovery in low-permeability oil fields. [ABSTRACT FROM AUTHOR]

Anisotropy strength in the Tres Vírgenes Volcanic Complex, Baja California Sur, Mexico, is analyzed employing 558 seismic events collected from 2009 to 2013. It was possible to delineate zones and volumes with the highest fracture densities, which are mainly located between the El Viejo and El Azufre volcanoes and around the La Reforma–El Azufre fault system, near some other mapped faults in the area (e.g., El Azufre, El Partido, El Volcán, El Viejo 1, and El Viejo 2 faults); likewise toward the La Virgen volcano and around the La Virgen-El Campamento and El Volcán faults. Individual delay times reached values of up to 0.16 s and an anisotropy percentage of up to 10.3%, with a pervasive anisotropy observed from at least a hypocentral distance of 3.5 km. High fracturing levels are observed from a depth of 7.0 km. Differences between splitting delays and the dominant frequency peaks obtained from the fast S phases allowed considering fracture systems with different degrees of fluid contents. Fractures with minor fluid contents were assumed for delay times higher than 0.03 s with lower dominant frequency peaks (< 1.0 Hz). Higher concentrations of fluid inclusions were assumed for splitting delays higher than 0.03 s but with larger dominant frequency peaks (> 1.0 Hz). Fractures systems chemically sealed or impermeable sealing caps were assumed for low splitting delays (< 0.02 s) with low dominant frequencies (< 1.0 Hz). These different fracture systems seem to be observed at least from 5- to 6-km depth intervals. Likewise, an analysis of the fast polarization directions with respect to different depth ranges (spanning from 3.0 to 8.0 km) has allowed observations of a strong NW–SE regional fracture system accompanied by minor NE–SW fracture systems. However, noteworthy variations from NW–SE to NE–SW, N–S, and E–W in fast polarization directions in rose diagrams have been preferentially observed for those seismic events deeper than 4–5 and 5–6 km in some areas, which could be indicating the location of magmatic bodies that probably caused the reorientation on fracture systems by changes in the local stress field. These magmatic bodies might be supported by a decrease in the dominant frequency peaks (lower than 1.0 Hz), percentage of anisotropy (from 0.1 to 2.5%), and S-wave velocities (from 1.0 to 2.7 km/s), which seem to be located from the 4.0-km depth but more concentrated from the 5–6-km depth interval. [ABSTRACT FROM AUTHOR]

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.)

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.)

Coal, a vital strategic resource, facilitates industrial development and socio-economic progress. Ensuring the high-quality development of the coal industry is crucial for national energy security and safety. Coal and gas outbursts are frequent hazards in coal mining processes. This research delves into the impact of heterogeneous coal seam strength on hydraulic fracturing propagation, utilizing both physical experimentation and the ABAQUS finite element approach. Experimental findings reveal distinct variations in water injection pressure profiles and fracturing fluid distribution patterns within coal seams of varying strengths, in contrast to those exhibiting uniform strength. When fractures propagate from a weaker to stronger coal seam region, a notable increase in pressure build-up effect is observed, leading to higher water injection pressure, wider fracture widths, augmented coal body displacement, and an elevated rate of rigidity reduction. In this study, the physical test results and numerical simulation results are verified with each other. After fractures propagate across the interface, zone with higher coal seam strength experience decreased fracture width, lower coal body displacement, and slower rates of rigidity decline compared to weaker seam zone. When fractures propagate from high to low coal seam areas, the fracture experiences instantaneous cross-boundary extension, resulting in a decrease in pore pressure, increased coal body displacement, and an elevated rate of rigidity decline. [ABSTRACT FROM AUTHOR]

Clean fracturing fluid exhibits desirable characteristics, such as low residue, easy flowback, minimal reservoir damage, and favorable rheology, making it highly adaptable. However, challenges remain in terms of high cost, large consumption, and poor stability. Hence, this study focuses on incorporating SiO2 nanoparticles into clean fracturing fluid to develop a novel nano‐modified system. Experimental tests were conducted to analyze the impact of mass fractions of hexadecyltrimethylammonium chloride (CTAC), sodium salicylate (Nasal), and SiO2 nanoparticles on the viscosity of the solution. The results indicate a significant increase in viscosity with higher mass fractions of SiO2. A nano‐modified clean fracturing fluid composition of 1.5 wt% CTAC, 0.4 wt% Nasal, and 0.1 wt% SiO2 was selected as it meets the technical specifications for fracturing fluid while exhibiting excellent elastic modulus (2.279 Pa) and viscous modulus (0.818 Pa), thereby displaying superior viscoelastic properties. Furthermore, the system maintains a viscosity above 20 mPa.s under temperature (70°C) and shear stress (170 s−1), indicating robust temperature and shear resistance to meet the demands of downhole fracturing and proppant transport. Based on rheological experimental data, a Carreau rheological model was established for the nano‐modified clean fracturing fluid. Considering particle interaction, wall blockage, and fluid filtration, a settlement model was modified with a correction coefficient, leading to the construction of a mathematical model for correcting proppant particle settling in fractures. The error between measured settlement velocity and calculated values remained within 10%. Finally, the migration law of proppant is studied, and the settlement law of proppant in fracturing fluid and fracture is clarified. [ABSTRACT FROM AUTHOR]

The migration law of proppants in slick water during fracturing is of great significance for field fracturing. A large‐scale visualized experimental device was utilized to test sand patterns for varying injection parameter combinations, and sensitivity parameters of proppant settlement are analyzed. Experimental results showed that when the viscosity of fluid is 5 mPa.s, proppants with 70–140 mesh and 8% sand ratio were used, the slick water for fracture initiation had a good sand‐carrying capacity, and there was no sand bank formed at the entrance of the fracture but the spreading of sands in fractures was insufficient. When slick water with a lower viscosity of 10 mPa.s, the proppant of 40–70 mesh and 10% sand ratio were used, massive proppants were filled within the fractures, and a high sand bank was formed in the deep of the fracture, while a poor‐filling effect appeared at the entrance of fracture. When the higher viscosity slick water of 20 mPa.s, proppants with 20–40 mesh and 20% sand ratio were used; with the growth of pump‐in rate, the distance between the sand front and fracture entrance increased, the height of the bank is lower, and the balance height stayed the same for various fracturing fluid and proppant combination. The injection parameters affected the sand bank patterns and made diverse bank shapes, which made it essential to modify the fracturing fluid and proppant combination in the field to improve the conductivity at the entrance of the fracture. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is a widely employed technique for stimulating unconventional shale gas reservoirs. Supercritical CO2 (SC-CO2) has emerged as a promising fracturing fluid due to its unique physicochemical properties. Existing theoretical models for calculating breakdown pressure often fail to accurately predict the outcomes of SC-CO2 fracturing due to the complex, nonlinear interactions among multiple influencing factors. In this study, we conducted fracturing experiments considering parameters such as fluid type, flow rate, temperature, and confining pressure. A fully connected neural network was then employed to predict breakdown pressure, integrating both our experimental data and published datasets. This approach facilitated the identification of key influencing factors and allowed us to quantify their relative importance. The results demonstrate that SC-CO2 significantly reduces breakdown pressure compared to traditional water-based fluids. Additionally, breakdown pressure increases with higher confining pressures and elevated flow rates, while it decreases with increasing temperatures. The multi-layer neural network achieved high predictive accuracy, with R, RMSE, and MAE values of 0.9482 (0.9123), 3.424 (4.421), and 2.283 (3.188) for training (testing) sets, respectively. Sensitivity analysis identified fracturing fluid type and tensile strength as the most influential factors, contributing 28.31% and 21.39%, respectively, followed by flow rate at 12.34%. Our findings provide valuable insights into the optimization of fracturing parameters, offering a promising approach to better predict breakdown pressure in SC-CO2 fracturing operations. [ABSTRACT FROM AUTHOR]

Composite flocculant PAFS-PDM was prepared from Polymeric aluminium ferric sulphate (PAFS) and Poly (diallyl dimethyl ammonium chloride) (PDM) in this study. A bacterium was selected from the soil near the shale gas exploitation platform as a bioflocculant-producing bacterium, and polysaccharide was extracted and combined with PAFS-PDM to obtain composite bioflocculant (CBF) to treat shale gas fracturing flowback fluid. The prepared CBF was characterized and the results showed that the prepared PAFS-PDM contained aluminium-iron hydroxyl polymer, which was a cationic flocculant. By measuring the turbidity removal rate and chemical oxygen demand (COD) removal efficiency, the function mechanism of CBF on the shale gas fracturing flowback fluid was discussed. The results showed that CBF had a stable treatment effect on fracturing flowback fluid when the pH value was about 7.0. With the increase of dosage, the coagulation efficiency increased first and then decreased. When the dosage of the CBF was 2500 mg·L−1, the treatment effect of shale gas fracturing flowback fluid was the best, and COD removal rate reached 89.43%. Through Zeta potential analysis, it was concluded that one of the coagulation mechanisms was electrical neutralization. According to the characterization results, it could be concluded that both adsorption bridging and charge neutralization mechanisms played important roles in the treatment of shale gas fracturing flowback fluids. [ABSTRACT FROM AUTHOR]

Drag reducers are indispensable components of slickwater fracturing fluids and play a pivotal role in the reconstitution of unconventional oil and gas reservoirs. Water‐in‐water emulsion (W/W) drag reducers have garnered significant attention owing to their rapid dissolution and environmentally benign properties. The solubility and viscosity enhancing ability of W/W drag reducers were further enhanced by synthesizing a novel W/W drag reducer through dispersion polymerization, thereby meeting the requirements of real‐time mixed fracturing construction technology. The solubility, viscosity enhancement, and synthesis state of the synthetic drag reducer were employed as evaluation criteria, whereby the synthetic systems underwent screening and optimization of the synthesis conditions. The final synthetic conditions were determined as follows: the monomer (AM and DMC) had a total mass concentration of 25 wt%, with an AM to DMC molar ratio of 95:5. The dispersion medium (sodium sulfate and sodium chloride) had a total mass concentration of 12 wt%, with a sodium sulfate to sodium chloride mass ratio of 1:2. The dispersion stabilizer PVP K60 had a mass concentration of 7 wt%. The initiator had a total mass concentration of 0.05 wt%, with an ammonium persulfate to sodium bisulfite mass ratio of 1:1. The reaction was conducted at 35°C and a stirring speed of 500 r min−1 for a duration of 8 h. The successful synthesis of the polymer was demonstrated using Fourier transform infrared spectroscopy. Environmental scanning electron microscopy and atomic force microscopy have characterized that the drag reducer has good viscosity enhancement potential. The performance evaluation results show that the solid content of drag reducer was 32.68%, and the residue content was 11.70 mg L−1. The viscosity enhancement rate of 1.3 wt% drag reducer was 93.7%. The dissolution time of 0.1 wt% drag reducer was only 25 s. The drag‐reduction rate of drag reducer reached 73.52%. Experimental results have proved that the drag reducer has the advantages of instant solubility, appreciable viscosity enhancement and drag‐reduction efficiency, fully meeting the real‐time mixing fracturing construction conditions, improving construction efficiency, and reducing construction costs. We expect that this study can broaden the application of W/W drag reducers in unconventional reservoir and provide a theoretical basis for field applications. [ABSTRACT FROM AUTHOR]

Purpose: Supercritical CO2 (SC–CO2) fracturing is a potential technology that creates a complex fracturing fracture network to improve reservoir permeability. SC–CO2-driven intersections of the fracturing fracture network are influenced by some key factors, including the disturbances generated form natural fractures, adjacent multi-wells and adjacent fractures, which increase the challenges in evaluation, control and optimization of the SC–CO2 fracturing fracture networks. If the evaluation of the fracture network is not accurate and effective, the risk of oil and gas development will increase due to the microseismicity induced by multi-well SC–CO2 fracturing, which makes it challenging to control the on-site engineering practices. Design/methodology/approach: The numerical models considering the thermal-hydro-mechanical coupling effect in multi-well SC–CO2 fracturing were established, and the typical cases considering naturally fracture and multi-wells were proposed to investigate the intersections and connections of fracturing fracture network, shear stress shadows and induced microseismic events. The quantitative results from the typical cases, such as fracture length, volume, fluid rate, pore pressure and the maximum and accumulated magnitudes of induced microseismic events, were derived. Findings: In naturally fractured reservoirs, SC–CO2 fracturing fractures will deflect and propagate along the natural fractures, eventually intersect and connect with fractures from other wells. The quantitative results indicate that SC–CO2 fracturing in naturally fractured reservoirs produces larger fractures than the slick water as fracturing fluid, due to the ability of SC–CO2 to connect macroscopic and microscopic fractures. Compared with slick water fracturing, SC–CO2 fracturing can increase the length of fractures, but it will not increase microseismic events; therefore, SC–CO2 fracturing can improve fracturing efficiency and increase productivity, but it may not simultaneously lead to additional microseismic events. Originality/value: The results of this study on the multi-well SC–CO2 fracturing may provide references for the fracturing design of deep oil and gas resource extraction, and provide some beneficial supports for the induced microseismic event disasters, promoting the next step of engineering application of multi-well SC–CO2 fracturing. [ABSTRACT FROM AUTHOR]

Clarifying the vertical propagation mechanism of hydraulic fractures (HFs) within thin interbedded rocks can provide the fundamental insights into cross-layer behaviors of HFs and valuable guidance for designing hydraulic fracturing pumping parameters in coal measure strata. Laboratory true-triaxial hydraulic fracturing experiments for horizontal wells are conducted using artificial thin interbedded samples consisting of the cement mortar encapsulating natural coal and mudstone interlayers. A three-dimensional (3D) fracture reconstruction method based on the fluorescent agent and laser scanning technique is proposed to quantitatively evaluate the stimulated reservoir area (SRA) and vertical fracture height (VFH) of HFs under different in-situ stresses, injection rates, fracturing fluid viscosities, lithological combinations and interfacial cementation strengths. Results show that the 3D geometry of HFs exhibits non-planar, asymmetric, and non-uniform propagation within thin interbedded rocks. The propagation patterns of HFs in thin interbedded rocks mainly include arresting, deflecting, penetrating and mixed pattern. The higher vertical stress difference coefficient (λV), injection rate and fracturing fluid viscosity facilitate the HF penetration through interlayers, thus increasing the SRA and VFH. A smaller horizontal stress difference coefficient (λH) induces the HF reorientation and significantly increases the SRA, although it has a minor impact on the vertical cross-layer propagation behaviors of HFs. Compared with the mudstone interlayer, the HF is prone to penetrate from the high-modulus sandstone layer into the low-modulus coal interlayer. The values of critical parameters (λV, injection rate, and fracturing fluid viscosity) for cross-layer propagation of HFs increase in the presence of weakly cemented lithological interfaces within thin interbedded rocks. When HFs propagate across interlayers, the injection pressure curve typically exhibits noticeable fluctuations and an upward trend during the injection of low-viscosity fracturing fluid. The key findings of this paper offer valuable insights into the vertical propagation mechanism of HFs and provide guidance for designing hydraulic fracturing treatments in coal measure strata. Highlights: The SRA and VFH of HFs within thin interbedded rocks are quantitatively evaluated using the 3D laser scanning technique under true-triaxial hydraulic fracturing experiments. The higher λV, injection rate and fracturing fluid viscosity facilitate the HF penetration through interlayers. The lower λH induces the HF reorientation and significantly increases the SRA. The critical parameter values for cross-layer propagation of HFs increase in the presence of weakly cemented lithological interfaces within thin interbedded rocks. [ABSTRACT FROM AUTHOR]

Relative permeability modifier (RPMs) is a water control technique that is implemented for enhancing gas recovery rates and prolonging well productive life during fracturing the tight gas reservoir. RPMs filtrate into formation for a certain depth along with the fracturing fluid to control water output by a "drag" effect on water phase only. To optimize RPM treatment, both experimental investigation and numerical simulation are used in this paper. In laboratory, transient core-flooding tests were conducted to investigate the water control performance of newly formulated polymer (RPM). The relative permeability of gas was corrected due to gas volume changes during displacement. The results showed that the selective water control effect of RPM by reducing water relative permeability dramatically with little impact on gas relative permeability. The RPM concentration was optimized as 0.01 %XSJ-14(A)+0.05 %XSJ-14(B) while injection volume as 5PV by comparison of relative permeability curves. A 2D fracture model of a tight gas model was built to compare the production before and after RPM treatment. The results of numerical simulation confirmed the different flow control effect of RPM on water and gas. A sensitivity analysis was conducted for the effect of fracture length, fracture conductivity, RPM filtration and RR value. The results indicate that there are limits of all the factor on RPM's water control performance. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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 & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing fluid, combined with a high-efficiency biological oil displacement agent (HE-BIO), which offers both production enhancement and environmental compatibility. Key experiments included tests on single-phase flow, core damage assessments, interfacial tension measurements, and oil recovery evaluations. The results showed that (1) the slickwater fracturing fluid effectively penetrates the rock matrix, enhancing oil recovery while minimizing environmental impact; (2) it causes substantially less damage to the reservoir compared to traditional guar gum fracturing fluid, especially in cores with little higher initial permeability; and that (3) oil recovery improves as HE-BIO concentration increases from 0.5% to 2.5%, with 2.0% as the optimal concentration for maximizing recovery rates. These findings provide a foundation for optimizing fracturing oil displacement fluids in tight sandstone reservoirs, highlighting the potential of the integrated fracturing fluid to enhance sustainable oil recovery. [ABSTRACT FROM AUTHOR]

Reliable forecasting of unconventional oil and gas well production has consistently been a hot and challenging issue. Most existing data-driven production forecasting models rely solely on a single methodology, with the application effects of other mainstream algorithms remaining unclear, which to some extent hinders the generalization and utilization of these models. To address this, this study commences with data preparation and systematically develops a novel forecasting model based on the adaptive fusion of multiple mainstream data-driven algorithms such as random forest and support vector machine. The validity of the model is verified using actual production wells in the Marcellus. A comprehensive evaluation of multiple feature engineering extraction techniques concludes that the main controlling factors affecting the production of Marcellus gas wells are horizontal segment length, fracturing fluid volume, vertical depth, fracturing section, and reservoir thickness. Evaluation models based on these primary controlling factors reveal significant differences in prediction performance among mainstream data-driven methods when applied to the dataset. The newly developed model based on adaptive fusion optimized by genetic algorithms outperforms individual models across various evaluation metrics, which can effectively improve the accuracy of production forecasting, demonstrating its potential for promoting the application of data-driven methods in forecasting unconventional oil and gas well production. Furthermore, this will assist enterprises in allocating resources more effectively, optimizing extraction strategies, and reducing potential costs stemming from inaccurate predictions. [ABSTRACT FROM AUTHOR]

This work presents a numerical study incorporating the impact of temperature variations along the fracture on the viscosity of fracturing fluids and consequently on proppant distribution in hydraulic fracturing. Traditional models have not considered non-uniform temperature distributions, resulting in less accurate predictions of proppant migration and distribution. The proposed model integrates the thermal variations to enhance the understanding of proppant dynamics under realistic field conditions. The proposed model is validated through physical experiments, demonstrating significant differences in proppant placement due to temperature- induced viscosity changes. Our results show that proppant distribution is substantially affected by lower temperatures at the fracture opening and higher temperatures at the distal end, contrasting sharply with distribution patterns observed under uniform viscosity conditions. As the temperature at the fracture opening decreases, the viscosity of the fracturing fluid increases, enhancing its capacity to transport proppant. The increased viscosity facilitates the transport of proppant deeper into the fracture, resulting in a reduction of the total amount of proppant near the fracture opening and a smaller stacking angle compared to those observed at fixed viscosities of 10, 100, and 200 mPa sThe findings offer critical insights into the mechanics of proppant flow, holding substantial theoretical and practical implications for optimizing hydraulic fracturing treatments. [ABSTRACT FROM AUTHOR]

Numerical simulations play a key role in the optimization of fracturing operation designs for unconventional reservoirs. Because of the presence of numerous natural discontinuities and pores, the rock masses of reservoirs can be regarded as fractured porous media. In this paper, a fully coupled discontinuous deformation analysis model is newly developed to simulate the hydromechanical processes in fractured and porous media. The coupling of fracture seepage, pore seepage, and fracture network propagation is realized under the framework of DDA. The developed model is verified with several examples. Then, the developed DDA model is applied to simulate the hydraulic fracturing processes in fractured porous rock masses, and the effects of rock mass permeability on fracturing are investigated. Our findings suggest that high rock permeability may inhibit the stimulation of fracture networks, while increasing the viscosity of fracturing fluids can enhance the fracturing efficiency. This study provides a valuable numerical tool for simulating hydromechanical processes in fractured and porous media and can be used to analyze various geo-mechanical problems related to fluid interactions. [ABSTRACT FROM AUTHOR]

In low-permeability fractured reservoirs, there is a generalized fluid displacement between the replacement fluid in the fracture and the matrix crude oil. This imbibition behavior plays a crucial role in the development of this type of reservoir. The experimental devices for studying static imbibition behavior are generally susceptible to air pollution on the surface of the test core and a long testing period; the experimental devices for studying dynamic imbibition behavior are generally unable to eliminate the driving action. A dual-purpose experimental setup and an experimental method for dynamic or static imbibition that can avoid the above defects were designed. A method of fracture fluid flow rate calculation and motor speed conversion is proposed, and the method is used to assist in setting the parameters of dynamic imbibition experiments. The device was applied to compare the experimental effects with the static imbibition bottle and the dynamic replacement imbibition, respectively, and the effect of fracture width on the dynamic imbibition of repellent oil was investigated. The results show that: the static imbibition recovery rate of the dynamic/static imbibition experimental device is 1.55 percentage points higher than that of the imbibition bottle; the dynamic imbibition recovery rate is 3–6 percentage points lower than that of the driving dynamic imbibition method, and it can reflect the influence of a single flow rate condition on the imbibition; imbibition in low-permeability fractured reservoirs is more likely to take place in the fracture in the interval of 50–100 μm in the width. [ABSTRACT FROM AUTHOR]

The deep continental crust represents a vast potential habitat for microbial life where its activity remains poorly constrained. Organic acids like acetate are common in these ecosystems, but their role in the subsurface carbon cycle - including the mechanism and rate of their turnover - is still unclear. Here, we develop an isotope-exchange 'clock' based on the abiotic equilibration of H-isotopes between acetate and water, which can be used to define the maximum in situ acetate residence time. We apply this technique to the fracture fluids in Birchtree and Kidd Creek mines within the Canadian Precambrian crust. At both sites, we find that acetate residence times are <1 million years and calculated a rate of turnover that could theoretically support microbial life. However, radiolytic water-rock reactions could also contribute to acetate production and degradation, a process that would have global relevance for the deep biosphere. More broadly, our study demonstrates the utility of isotope-exchange clocks in determining residence times of biomolecules with possible applications to other environments. Trapped in rock fractures miles below the surface are saline waters that have been isolated for millions of years. In these most remote environments exists an active turnover of dissolved organic molecules, an active carbon cycle. [ABSTRACT FROM AUTHOR]

Mussel‐inspired materials have been widely studied due to their excellent adhesion and self‐healing properties, but few studies have introduced this interesting property into the fracturing development of deep/ultra‐deep oil and gas fields. Herein, a new type of mussel‐inspired delayed crosslinking gel fracturing fluid is reported, which is formed by mussel‐inspired polymers containing many catechol groups and organic zirconium delayed crosslinkers. The strong supramolecular interaction in mussel‐inspired polymers can construct a more complex and stable dually cross‐linked polymer network based on conventional chemical crosslinking, to cope with harsh conditions such as high temperature and shear in reservoirs. After shearing at 200 °C, the reserved viscosity of mussel‐inspired delayed crosslinking gel is as high as 95 mPa·s. More importantly, the viscosity of gel remains basically unchanged at 25 °C, and the cross‐linking is completed within 300 s at 90 °C. The chemical force probe atomic force microscope (AFM) technology has successfully demonstrated that catechol groups are the main source of supramolecular interaction in mussel‐inspired polymers. The molecular simulation results show that due to the addition of catechol groups, the hydrogen bond interactions within the mussel‐inspired polymers molecules are enhanced. And the additional hydrogen bonds formed are more stable at high temperature. [ABSTRACT FROM AUTHOR]

The stable isotope compositions of sulphur (δ34S) and oxygen (δ18O) in barite are frequently used as proxies for microbial sulphate reduction (MSR) in diverse environments, such as in relation to anaerobic oxidation of methane in marine cold seeps. There, isotopically heavy barite is used as a marker for MSR from a sulphate pool that has undergone semi-closed system conditions. Closed-system MSR is also a commonly observed feature in igneous rock hosted fracture aquifers, as shown by extremely 34S-enriched pyrite. What is less well-constrained is whether δ34S in barite can be used as a proxy for MSR in such systems. Here we explore the microscale heterogeneity of δ34S and δ18O via secondary ion mass spectrometry and the trace element Sr via LA-ICP-MS maps in barite precipitated in granite-hosted boreholes during a 17-year experiment, at Äspö, Sweden. We compare it with δ18Osulfate, δ34Ssulfate, and δ34Ssulfide of the fracture fluids and with paragenetic pyrite with δ34S values reflecting closed system MSR. The δ18O values in barite (+9.4 to +16.9 ‰) represent two generations of barite, one with low values and one with high values. The latter are likely impacted by sulphur disproportionating or -oxidizing bacteria. The barite reflects a much smaller span in δ34S (+14.5 to +28.6 ‰) than the pyrite (−47.2 to +53.3 ‰). This lack of extremely high δ34Sbarite values is proposed to be due to that barite saturation only occurred in the early parts of the Rayleigh cycle. Additionally, fluid migration has affected the δ34S values to lower values, accompanied by higher Sr concentrations. Taken together, barite δ34S values cannot be regarded as a reliable independent proxy for MSR in deep sulphate-poor igneous rock hosted aquifers. However, the relation between the δ34S values of coeval barite and pyrite is regarded as a useful proxy for MSR-related fractionation during early stages of MSR. [ABSTRACT FROM AUTHOR]

The Self-Propping Phase-transition Fracturing Technology (SPFT) represents a novel and environmentally friendly approach for a cost-effective and efficient development of the world's abundant unconventional resources, especially in the context of a carbon-constrained sustainable future. SPFT involves the coupling of Thermal, Hydraulic, Mechanical, and Chemical (THMC) fields, which makes it challenging to understand the mechanism and path of hydraulic fracture propagation. This study addresses these challenges by developing a set of THMC multifield coupling models based on SPFT parameters and the physical/chemical characteristics of the Phase-transition Fracturing Fluid System (PFFS). An algorithm, integrating the Finite Element Method, Discretized Virtual Internal Bonds, and Element Partition Method (FEM-DVIB-EPM), is proposed and validated through a case study. The results demonstrate that the FEM-DVIB-EPM coupling algorithm reduces complexity and enhances solving efficiency. The length of the hydraulic fracture increases with the quantity and displacement of PFFS, and excessive displacement may result in uncontrolled fracture height. Within the parameters considered, a minimal difference in fracture length is observed when the PFFS amount exceeds 130 m3, that means the fracture length tends to stabilize. This study contributes to understanding the hydraulic fracture propagation mechanism induced by SPFT, offering insights for optimizing hydraulic fracturing technology and treatment parameters. [ABSTRACT FROM AUTHOR]

Introduction/purpose: Fractured formations recently gained significant interest as a landscape for securing both energy and groundwater demands, However, the dual role of fracture in transporting fluids and contaminants underscores the need for further investigations to mitigate the impact on human health. This study aims to numerically investigate the combined effect of particle density and flow velocity on their transport and deposition in different fracture orientations. Methods: A 2D particle tracing simulation was implemented accounting for drag and gravity forces on a smooth fracture. The derived particle numbers under the studied scenario e.g., fracture orientation, particle density, and flow velocity, were fitted to a 1D advection-dispersion equation with a deposition term. Results: The model elucidated that both particle densities yielded an increase in the normalized concentration in non-horizontal scenarios as the fracture orientation angle increased. The overall increment led to an observed decrease in the deposition coefficients and was associated with an increase in the dispersion coefficients. Hence the effect was more pronounced for denser particles where gravitational settling dominated, particularly in horizontal fractures. Less dense particles (1.05 g/cm³) were more strongly influenced by hydrodynamic forces, exhibiting lower overall deposition and dispersion across all fracture orientations. Additionally, increased flow velocity enhanced mechanical mixing and amplified dispersion and deposition coefficients. Conclusion: The findings demonstrated a clear dependency on the combined effect of fracture orientation, particle density, and flow velocity. These valuable insights into particle transport mechanisms in fractured media have applications in subsurface flow, contaminant migration, and reservoir engineering. [ABSTRACT FROM AUTHOR]

Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing. [ABSTRACT FROM AUTHOR]

Tri-axial fracturing studies were carried out to understand the impact of lateral mechanical parameters on fracture propagation from multiple in-plane perforations in horizontal wells. Additionally, the discussion covered the effects of geology, treatment, and perforation characteristics on the non-planar propagation behavior. According to experimental findings, two parallel transverse fractures can be successfully initiated from in-plane perforation clusters in the horizontal well because of the in-plane perforation, the guide nonuniform fishbone structure fracture propagation still can be exhibited. The emergence of transverse fractures and axial fractures combined as complex fractures under low horizontal principal stress difference and large pump rate conditions. The injection pressure was also investigated, and the largest breakdown pressure can be also found for samples under these conditions. The increase in perforation number or decrease in the cluster spacing could provide more chances to increase the complexity of the target stimulated zone, thus affecting the pressure fluctuation. In a contrast, the increase in fracturing fluid viscosity can reduce the multiple fracture complexity. The fracture propagation is significantly affected by the change in the rock mechanical properties. The fracture geometry in the high brittle zone seems to be complicated and tends to induce fracture reorientation from the weak-brittle zone. The stress shadow effect can be used to explain the fracture attraction, branch, connection, and repulsion in the multiple perforation clusters for the horizontal well. The increase in the rock heterogeneity can enhance the stress shadow effect, resulting in more complex fracture geometry. In addition, the variable density perforation and temporary plugging fracturing were also conducted, demonstrating higher likelihood for non-uniform multiple fracture propagation. Thus, to increase the perforation efficiency along the horizontal well, it is necessary to consider the lateral fracability of the horizontal well on target formation. [ABSTRACT FROM AUTHOR]

Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymerbased fracturing fluids (such as guar gum (GG), polyacrylamide (HPAM), etc.) are high-viscosity fluids formed by viscosifiers and crosslinking agents, the degree of gel breakage after the fracturing operation directly influences the damage degree to the reservoir matrix and the mobility of oil angd gas produced from the reservoir into the wellbore. This study compared the viscosity, molecular weight, and particle size of the fracturing fluid after gel breakage prepared by GG and HPAM as viscosifiers, as well as evaluate their damage to the core. Results show that the viscosities of the gel-breaking fluid increased with the concentration of the viscosifier for both the HPAM-based and GG-based fracturing fluids. For the breaking fluid with the same viscosity, the molecular weight in the HPAM-based gel-breaking fluid was much larger than that in the GG-based system. Moreover, for the gel-breaking fluid with the same viscosity, the molecular particle size of the residual polymers in the HPAM-based system was smaller than that in the GG-based system. The damage to the core with the permeability of 1 × 10-3 μm² caused by both the HPAM-based and GG-based gel-breaking fluids decreased with the increase in the solution viscosity. For the gel-breaking fluid systems with the same viscosity (i.e., 2-4 mPa s), the damage of HPAM-based fracturing fluid to low-permeability cores was greater than the GG-based fracturing fluid (45.6%e80.2%) since it had a smaller molecular particle size, ranging from 66.2% to 77.0%. This paper proposed that the damage caused by hydraulic fracturing in rock cores was related to the partilce size of residual polymers in gel-breaking solution, rather than its molecular weight. It was helpful for screening and optimizing viscosifiers used in hydraulic fracturing process. [ABSTRACT FROM AUTHOR]

The main objective is to optimize the development of shale gas-rich areas by predicting seismic sweet spot parameters in shale reservoirs. We systematically assessed the fracture development, fracture gas content, and rock brittleness in fractured gas-bearing shale reservoirs. To better characterize gas-bearing shale reservoirs with tilted fractures, we optimized the petrophysical modeling based on the equivalent medium theory. Based on the advantages of shale petrophysical modeling, we not only considered the brittle mineral fraction but also the combined effect of shale porosity, gas saturation, and total organic carbon (TOC) when optimizing the brittleness index. Due to fractures generally functioning as essential channels for fluid storage and movement, fracture density and fracture fluid identification factors are critical geophysical parameters for fractured reservoir prediction. We defined a new fracture gas indication factor (GFI) to detect fracture-effective gas content. A new linear PP-wave reflection coefficient equation for a tilted transversely isotropic (TTI) medium was rederived, realizing the direct prediction of anisotropic fracture parameters and the isotropic elasticity parameters from offset vector tile (OVT)- domain seismic data. Synthetic seismic data experiments demonstrated that the inversion algorithm based on the LP quasinorm sparsity constraint and the split-component inversion strategy exhibits high stability and noise resistance. Finally, we applied our new prediction method to evaluate fractured gasbearing shale reservoirs in the Sichuan Basin of China, demonstrating its effectiveness. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is widely recognized as a key technology for enhancing coalbed methane production. The fracturing fluid has physicochemical reactions with the coal fractures, along with their duration, critically affecting fracture permeability, thereby determining the effectiveness of the technology. However, the study has not received enough attention. In this study, coal fracture seepage tests were carried out using in situ continuous injection of fracturing fluid. The seepage evolution of viscoelastic surfactant fracturing fluid (VESFF) was investigated at different times (0, 1, 2, 3, 4, and 5 days), and de-ionized water (DW) and potassium chloride solution (KCL) were used for comparison. The results showed that the flow rate increased compared to initial flow rate after VESFF treatment for two to four days, while the flow rate could not be recovered after DW and KCL treatment. The optimal treatment duration for VESFF was two days: marked by a sevenfold increase in the flow rate, an 84% increase in initial hydraulic aperture, and minimal momentum loss. After two more days of VESFF treatment, the pressure gradient and effective confining pressure became greater than 6 MPa/m and 3.5 MPa, respectively, and showed a significant excessive discharge characteristics (β < 0), which resulted from the generation and dilation of microcracks, increasing the number of flow channels due to coupled fluid–mechanical behavior. The degree of flow nonlinearity decreased with increasing VESFF treatment duration and increased with increasing effective confining pressure. These results have profound implications for optimal treatment duration and mechanism of VESFF strengthening coal fracture seepage. [ABSTRACT FROM AUTHOR]

Exploring the adaptability of CO2 and water-based fracturing to shale oil reservoirs is important for efficiently developing shale oil reservoirs. This study conducted fracturing experiments and acoustic emission (AE) monitoring on the Jurassic continental shale. Based on high-precision computed tomography scanning technology, digital reconstruction analysis of fracture morphology was carried out to quantitatively evaluate the complexity of fractures and the stimulation reservoir volume (SRV). The results show that the fracturing ability of a single water-based fracturing fluid is limited. Low-viscosity fracturing fluid tends to activate thin layers and has limited fracture height. High-viscosity fracturing fluid tends to result in a wide and simple fracture. A combination injection of low-viscosity and high-viscosity water-based fracturing fluid can comprehensively utilize the advantages of low-viscosity and high-viscosity fracturing fluids, effectively improving the complexity of fractures. CO2 fracturing is adaptable to Jurassic shale. The breakdown pressure of the supercritical CO2 (SC-CO2) fracturing is low. Branch fractures form, and laminas activate during SC-CO2 fracturing due to its high diffusivity. Under high-temperature and high-pressure conditions, the aqueous solution formed by mixing CO2 with water can promote the formation of complex fractures. Compared with water-based fracturing fluid, the complexity of fractures and effective stimulation reservoir volume (ESRV) increased by 8.7% and 47.6%, respectively. There is a high correlation between SRV and ESRV, and the proportion of AE shear activity is also highly correlated with the complexity of fractures. The results are expected to provide better fracturing schemes and effectiveness for continental shale oil reservoirs. [ABSTRACT FROM AUTHOR]

Huff‐n‐puff (HnF) is a crucial technology for effectively enhancing the oil recovery (EOR) of tight oil reservoirs. Soaking period is the primary platform for injection medium interacting with formation fluid and reservoir rock in HnF. Elucidating the micro‐percolation mechanism of the soaking period is immensely significant for guiding oilfield production practices. The present study established a physical simulation method combining HnF experiments with nuclear magnetic resonance to reveal the microscopic percolation mechanisms, including water, fracturing fluid, and surfactant. Furthermore, the impacts of soaking time, HnF cycles, wettability, and pore structure on oil recovery degree were quantified. The results demonstrate the crucial significance of wettability and pore structure in the soaking period. The dominant mechanism during water HnF in reservoirs characterized by well‐connected pore networks and minimal clay pores is micropore imbibition, while conversely, macropore displacement plays a predominant role. The oil recovery degree of fracturing fluid HnF primarily relies on mitigating solid‐fluid forces within macropores. The surfactant HnF in preferential water‐ and oil‐wet reservoirs is primarily governed by oil films stripped from macropore walls and micropore imbibition, respectively. Specifically, water and fracturing fluid HnF are suitable for shorter soaking time and fewer HnF cycles, whereas the surfactant HnF exhibits an inverse relationship. [ABSTRACT FROM AUTHOR]

The Tarim area, characterized by deep reservoirs, high temperatures, and limited fresh water resources, necessitates a fracturing fluid system that exhibits excellent temperature shear resistance, low friction, and salinity tolerance. This study presents the development of a zwitterionic hydrophobic polymer, HPC-5, as an effective thickener using five types of polymeric monomers, including AM, AA, DMC, AMPS, and a non-ionic hydrophobic monomer. The method employed for synthesis was free-radical polymerization in solution. A series of experiments including viscosity measurement with variation of salinity, solubility and drag reduction test, crosslinking test, thermal and shear resistance, sand-carrying test, gel breaking evaluation, and core damage test were conduct under the simulated reservoir conditions. The zwitterionic design imparts great salt tolerance to HPC-5, and the apparent viscosities of HPC-5 solutions can maintain comparably high values with 10×104 ppm NaCl and CaCl2 concentration. Meanwhile, the molecules of HPC-5 associate with each other to form tight net structures, resulting in an excellent viscoelasticity of the solution. To achieve high pump rate during hydraulic fracturing operation in ultra-deep reservoirs, the delayed crosslinking agent ZDC-L was prepared for forming a delayed crosslinking gel fracturing fluid system using reservoir brine, and the drag reduction rate can reach over 70% before crossing link within 4 min. Under pH = 4 conditions, the crosslinking time can be significantly delayed to over 4 min while maintaining exceptional temperature resistance up to 160 ℃ for the gel. These properties make it highly suitable for hydraulic fracturing operations in ultra-deep wells with temperatures reaching up to 7000 m depth at pump rates of 4~5m3/min. [ABSTRACT FROM AUTHOR]

The effectiveness of hydraulic fracturing is determined by the location of fracture initiation and the propagation. Previous research paid more attention to the control effect of geostress and construction-related parameters on the fracturing and propagation of fractures induced by hydraulic fracturing but ignored the important influence of fracturing fluid flow distribution when soft coal and hard coal interbed. In view of this, a model for the amount of fracturing fluids entering soft–hard coal interbedded strata was established. Meanwhile, the relationship among the strength differences between soft and hard coals, the perforation aperture, the coal seam thickness, the thickness ratio of hard coal, and the ratio of fracturing fluids entering hard coal was analyzed. The effect of the ratio of fracturing fluids flowing into hard coal on fracturing and gas production was discussed. On this basis, the fracturing construction suggestions under different thickness ratios of soft and hard coals were proposed. The results reveal that fracturing fluids always preferentially enter the soft coal with a lower strength, which causes an increased frictional resistance of fracturing fluid migration in soft coal, resulting in the redistribution of fracturing fluids entering coal seams and finally achieving the distribution balance. The strength differences between soft and hard coals, the perforation aperture, and seam thickness are negatively correlated with the proportion of fracturing fluids flowing into hard coal. The thickness of hard coal is positively correlated with that of hard coal; when the reservoir gas production potential is similar and the proportion of fracturing fluids entering hard coal does not exceed 30%, stable daily gas production is unlikely to exceed 800 m3/day; when the proportion of fracturing fluids entering hard coal exceeds 70%, daily gas production exceeds 1,000 m3/day. The results provide theoretical support for optimizing hydraulic fracturing schemes when soft and hard coals are interbedded. [ABSTRACT FROM AUTHOR]

As a crucial factor that influences the hydraulic fracturing effectiveness of coal seams, fracturing fluids have garnered increasing attention. Among them, acid fracturing fluids have demonstrated positive impact on the pore transformation of coal, but high-strength acid fracturing fluids can cause corrosion damage to mechanical equipment. In this study, we employed acetic acid to formulate four types of weak acid fracturing fluids with varying concentrations and conducted soaking experiments. We analyzed the changes in the physical and chemical structure of coal samples before and after treatment using Fourier-transform infrared spectroscopy and X-ray diffraction analysis. The changes in the pore structure of coal samples before and after treatment were characterized by nitrogen adsorption and scanning electron microscopy. Our findings indicate the following: (1) The effects of different concentrations of acetic acid fracturing fluid on functional groups and microcrystalline structure vary. The 5% concentration fracturing fluid had the most significant impact on the organic structure of coal samples, with decreases in the area of hydroxyl structure, aliphatic structure, and oxygen-containing structure of 2.97%, 1.37%, and 0.68%, respectively. The 6% concentration fracturing fluid had the most significant impact on crystal structure, leading to a high degree of recrystallization and a fragile crystal network structure. (2) Fracturing fluids with concentrations below 7% can increase the number of mesopores and simplify the pore structure, while concentrations above 7% can lead to an increase in micropores and a more complex pore structure. (3) After the action of fracturing fluid, carbonate minerals are dissolved, and the pores of coal samples increase. However, excessively high concentrations of acetic acid fracturing fluid can facilitate shedding of mineral particles and block some pore channels, worsening the connectivity between pores. (4) The octadecylamine acetate formed by the combination of octadecylamine and acetic acid develops as a partial film on the surface of a coal body, reducing the roughness of the fracture surface and facilitating the flow of the fracturing fluid. Our findings provide theoretical support for the preparation and selection of weak acid fracturing fluids. [ABSTRACT FROM AUTHOR]

Accurate prediction of fracture volume and morphology in horizontal wells is essential for optimizing reservoir development. Traditional methods struggle to capture the intricate relationships between fracturing effects, geological variables, and operational factors, leading to reduced prediction accuracy. To address these limitations, this paper introduces a multi-task prediction model designed to forecast fracturing outcomes. The model is based on a comprehensive dataset derived from fracturing simulations within the Long 4 + 5 and Long 6 reservoirs, incorporating both operational and geological factors. Pearson correlation analysis was conducted to assess the relationships between these factors, ranking them according to their influence on fracturing performance. The results reveal that operational variables predominantly affect Stimulated Reservoir Volume (SRV), while geological variables exert a stronger influence on fracture morphology. Key operational parameters impacting fracturing performance include fracturing fluid volume, total fluid volume, pre-fluid volume, construction displacement, fracturing fluid viscosity, and sand ratio. Geological factors affecting fracture morphology include vertical stress, minimum horizontal principal stress, maximum horizontal principal stress, and layer thickness. A multi-task prediction model was developed using random forest (RF) and particle swarm optimization (PSO) methodologies. The model independently predicts SRV and fracture morphology, achieving an R2 value of 0.981 for fracture volume predictions, with an average error reduced to 1.644%. Additionally, the model's fracture morphology classification accuracy reaches 93.36%, outperforming alternative models and demonstrating strong predictive capabilities. This model offers a valuable tool for improving the precision of fracturing effect predictions, making it a critical asset for reservoir development optimization. [ABSTRACT FROM AUTHOR]

The efficient development of carbonate rock reservoirs with rich oil and gas resources has become a hot topic and a focal point in the current oil and gas industry. The development of carbonate rock oil and gas reservoirs differs from that of sandstone reservoirs. Although gas flooding, water flooding, and chemical flooding have been carried out in recent years, the development is still unsatisfactory, and the on-site application of technologies such as nanoparticles is on the rise. For the future development of acid fracturing technology, accurate reservoir geological description, core printing based on additive manufacturing technology, the development of new acid fracturing techniques, and the research and development of acid fracturing equipment will have great research potential and economic value in the development of carbonate rock oil and gas reservoirs. Under the development background of high-temperature deep reservoirs, this paper comprehensively reviews unconventional acidizing fracturing fluids in carbonate rock oil and gas reservoirs. We introduce the main components, corresponding mechanisms of action, current research achievements, and advantages of promising acid fracturing fluids, including thickened acids. We focus on the application and limitations under harsh conditions of high temperature and high salinity while also focusing on the development of thickened acid fracturing technology. The thickening agent is the core of a thickened acid solution. Therefore, this article fully reviews the structure, sources, advantages and disadvantages, as well as the current development status of biological, cellulose, and synthetic polymer thickeners. Synthetic polymers, low-molecular-weight polymers, and small-molecular compound crosslinkers provide clues for temperature and salt-resistant thickeners and also promote the development of tight reservoirs. [ABSTRACT FROM AUTHOR]

In order to comprehensively understand the complex fracture mechanisms in thick and loose sandstone formations, we have carefully developed a coupled finite element numerical model that captures the complex interactions between fluid flow and solid deformation. This model is the cornerstone of our future exploration. Based on this model, the crack propagation problem of hydraulic fracturing under different engineering and geological conditions was studied. In addition, we conducted in-depth research on the key factors that shape the geometry of hydraulic fractures, revealing their subtle differences and complexities. It is worth noting that the sharp contrast between the stress profile and mechanical properties between the production layer and the boundary layer often leads to fascinating phenomena, such as the vertical merging of hydraulic fracture propagation. The convergence of cracks originating from adjacent layers is a recurring theme in these strata. Sensitivity analysis clarified our understanding, revealing that increased elastic modulus promotes longer crack propagation paths. As the elastic modulus increases from 12 GPa to 18 GPa, overall, the maximum crack width slightly decreases, with a less than 10% reduction rate. The increased fluid leakage rate will significantly shorten the length and width of hydraulic fractures (with a maximum decrease of over 70% in fracture width). The increase in viscosity of fracturing fluid causes a change in fracture morphology, with a reduction in length of about 32% and an increase in fracture width of about 25%. It is worth noting that as the leakage rate of fracturing fluid increases, the importance of the viscosity of fracturing fluid decreases relatively. Strategies such as increasing fluid viscosity or adding anti-filtration agents can alleviate these challenges and improve the efficiency of fracturing fluids. In summary, our research findings provide valuable insights that can provide information and optimization for hydraulic fracturing filling and fracturing strategies in loose sandstone formations, promoting more efficient and influential oil and gas extraction work. [ABSTRACT FROM AUTHOR]

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (IR) to denote the intensity of these reactions. Based on the IR value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater IR, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well. [ABSTRACT FROM AUTHOR]

Stress interference is the main factor affecting hydraulic fracture propagation during multi-well hydraulic fracturing; stress interference is influenced by fracture bending, fracture hits, and asymmetric fracture propagation. To investigate the role of stress interferences among hydraulic fractures with nonuniform stress distribution in an inhomogeneous formation, a hydromechanical coupling extended finite element method was adopted to investigate the fracturing paths that occurred during the first fracturing–fracturing fluid flowback–repeat fracturing process; the asymmetric fracturing that occurred at different child well locations was also studied. The results showed that the area affected by fracturing-induced stress formed a "butterfly type" area. For child wells located within the zone, stress interference resulted in asymmetric fracture propagation; meanwhile, for child wells located outside this zone, stress interference resulted in symmetric fracture geometry. The effect of stress interference on the asymmetry of child well fracture wings was found to be negatively correlated with the distance between the parent well and the child well. [ABSTRACT FROM AUTHOR]

The heterogeneity in fracture formation significantly influences the hydraulic fracture propagation among adjacent wells, underscoring the urgency to comprehend the underlying fracture mechanisms. Specifically, in shale gas or oil extraction fracturing operations, stress interactions among neighboring fracturing clusters, or mutual interference during the propagation of parallel fractures, are commonplace. At present, there is relatively little research on the sensitivity parameters of adjacent borehole fracture propagation morphology. Consequently, we employed ABAQUS software 2022 to construct a numerical model simulating the fracturing of adjacent boreholes in opposing directions. Upon validating the model's fidelity, we systematically explored the influence of various engineering and geological factors on fracture morphology and propagation length. Our findings revealed a three-phase evolution: independent fracture propagation, subsequent mutual repulsion, and, ultimately, mutual attraction. It is worth noting that increasing the elastic modulus from 10 GPa to 80 GPa, and increasing the crack length by 16.30%, is beneficial for crack propagation, while the horizontal stress difference profoundly shapes the crack mode, but has a relatively small impact on the overall crack length. When HSD increases from 0 MPa to 15 MPa, the total crack length only changes by 1.24%. In addition, the filtration coefficient of the reservoir is a key determining factor that has a significant impact on the morphology and length of cracks generated by adjacent boreholes. Increasing the filtration coefficient from 1 × 10−14 m3/s/Pa to 5 × 10−12 m3/s/Pa reduces the total length of cracks by 60.77%. Notably, an optimal injection rate exists, optimizing fracturing outcomes. Conversely, the viscosity of the fracturing fluid exerts a limited influence on fracture morphology and length within the confines of this simulation, allowing for the selection of a suitable viscosity to ensure smooth proppant transport during actual fracturing operations. In designing fracturing parameters, it is imperative to aim for sufficient fracture propagation length while harnessing "stress interference" to foster the development of intricate fracture networks. Ultimately, our research findings serve as a solid foundation for engineering practices involving hydraulic fracture propagation in adjacent boreholes undergoing opposing fracturing operations. [ABSTRACT FROM AUTHOR]

The characteristics of tight matrix, underdeveloped natural fractures, small pore throat radius, poor pore connectivity, and abundant clay minerals result in a high potential for damage to the tight sandstone reservoirs of the Shaximiao Formation in the Qiulin Block in the Sichuan Basin. In order to reduce the retention damage caused by fracturing fluid to the tight sandstone reservoir, a low damage fracturing fluid system applicable to the target reservoir is developed in this work, and the indoor performance meets the requirements of on‐site fracturing operation. A low‐damage, heat‐resistant, shear‐stable amphiphilic polyacrylamide (PAAD) was prepared by free radical polymerization in aqueous solution using acrylamide, acrylic acid, and methacryloyloyloxyethyl dimethyloctadecyl ammonium bromide (DM18) as the monomers. The amphoteric polyacrylamide was characterized by Fourier infrared spectroscopy, nuclear magnetic resonance spectroscopy (1H NMR), light scattering molecular weight determination, and thermogravimetric analysis. Fracturing fluids were formulated with the amphiphilic hydrophobic associative polymer PAAD as a drag‐reducing agent, the fluorine‐containing and nonionic complex surfactant FD1 as a clean‐up additive, CT10‐4B as a bactericide and CT1‐12 as an emulsion breaker. The fracturing fluid formulation was preferred, and the performance of the fracturing fluid was evaluated in terms of temperature resistance and shear resistance, drag reduction, anti‐expansion, and core damage. The fracturing fluid showed good temperature and shear resistance, with a viscosity retention of 58.4% at 120°C and 170 s−1 shear for 1 h. At a loading of 0.1%, the drag reduction rate reaches 72.3%, the anti‐expansion rate of the gel‐breaking fluid is 86.04%, and the damage rate to the tight sandstone core is 16.25%. The results show that the fracturing fluid has good heat resistance and shear stability, as well as low damage and good resistance reduction and anti‐expansion properties. This work can provide new strategies for designing polymeric fracturing fluids with low damage, good heat resistance and shear stability. [ABSTRACT FROM AUTHOR]

Application of hydraulic fracturing to produce “unconventional” oil and gas from shale formations and other low-permeability geological units has raised concerns about the potential environmental impacts, including potential adverse effects of fracturing fluids (FF) on groundwater. In this study, laboratory batch test experiments and new analytical methods were developed to analyze FF chemicals as potential indicators (tracers) to detect impacts of fracturing fluids on groundwater. The tests, conducted over 101–196 days, included FF with synthetic chemicals (~40,000–4,000,000 µg/L), placed in batches with groundwater and sediment at 5° and 25 °C, along with sterile controls. Using the new methods, measurable concentrations of the FF chemicals were many orders in magnitude lower (~3000 to 3,000,000 X) compared to their concentrations in synthetic fracturing fluids, indicating that these chemicals are excellent candidates as indicators of FF contamination in groundwater, if they are relatively persistent, and not prone to extensive loss by sorption during migration in the subsurface. Variable sorption and degradation of the chemicals was observed in both batch and column tests. Sorption was negligible (sorption coefficient, Kd~0.0) for some synthetic chemicals (polyethylene glycol, ethanolamines, isopropanol, and ethyl hexanol) in some tests. At the other extreme, strong sorption was observed for some of the higher molecular weight cocamido propyl betaine (max Kd = 1.17) and polyethylene glycol (max Kd = 1.12) components, and triethanolamine (max Kd = 0.47) in other tests. Apparent loss by degradation was observed for each chemical in some tests, but negligible in others. The shortest apparent half-lives were for isopropanol and ethyl hexanol at 25 °C (t½ < 11 days), and the most persistent synthetic chemicals were polyethylene glycols (t½ ≥ 182 d) and the ethanolamines (t½ ≥ 212 d). Of the potentially diagnostic FF chemicals investigated, the relatively hydrophilic and persistent lower molecular weight polyethylene glycols are some of the most promising as potential indicators of contamination of groundwater by FF.

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.)

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.)

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.)

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.)

To solve problems such as inadequate proppant carrying capacity, a complex viscosity changing process, and limited environmental friendliness associated with traditional slick water fracturing fluids, a variable viscosity friction reducer called Jianghan friction reducer (JHFR) with low damage, high drag reduction, and strong proppant‐carrying capacity is prepared by inverse emulsion polymerization. The properties of JHFR are investigated by viscometer, JHFR‐II high‐temperature and high‐pressure slick water drag reduction rate tester, surface tension meter, and JHCQ Core dynamic damage evaluation device. The result shows that the dissolution time of JHFR is less than 120 s. The drag reduction of 0.08 wt% JHFR (4.83 mPa s) is 80.3%. When the concentration of JHFR increases from 0.08 to 0.8 wt %, the viscosity of the JHFR increases from 4.83to 97.41 mPa s. After sheared at 90°C and 170 s−1 for 60 min, the viscosity of 0.8 wt% JHFR still maintains 51 mPa s. The damage rate of JHFR to core matrix permeability is lower than 30%. JHFR also shows the advantages of easy breakage and low residue. It provides guidance for the design and selection of fracturing fluid for unconventional oil and gas reservoir development. [ABSTRACT FROM AUTHOR]

The wettability of the proppant is crucial in optimizing the flowback of fracturing fluids and improving the recovery of the produced hydrocarbons. Neutral wet proppants have been proven to improve the fluid flow by reducing the interaction between the fluid and the proppant surface. In this study, a lightweight amphiphobic proppant (LWAP) was prepared by coating a lightweight ceramic proppant (LWCP) with phenolic resin, epoxy resin, polytetrafluoroethylene (PTFE), and trimethoxy(1H,1H,2H,2H-heptadecafluorodecyl)silane (TMHFS) using a layer-by-layer method. The results indicated that the LWAP exhibited a breakage ratio of 2% under 52 MPa (7.5 K) closure stress, with an apparent density of 2.12 g/cm3 and a bulk density of 1.21 g/cm3. The contact angles of water and olive oil were 125° and 104°, respectively, changing to 124° and 96° after displacement by water and diesel oil. A comparison showed that the LWAP could transport over a significantly longer distance than the LWCP, with the length increasing by more than 80%. Meanwhile, the LWAP displayed notable resistance to scale deposition on the proppant surface compared to the LWCP. Furthermore, the maintained conductivity of the LWAP was higher than that of the LWCP after displacement by water and oil phases alternately. The modified proppant could minimize production declines during hydrocarbon extraction in unconventional reservoirs. [ABSTRACT FROM AUTHOR]