Search Results (58)

Understanding particle transport in rough-walled fractures is essential for predicting flow behavior, clogging, and permeability evolution in natural and engineered subsurface systems. This study develops a fully coupled CFD–DEM framework to investigate how self-affine fractal roughness, represented by the Joint Roughness Coefficient (JRC), governs fluid–particle interactions across multiple scales. Nine fracture geometries with controlled roughness were generated using a fractal-based surface model, enabling systematic isolation of roughness effects. The results show that increasing JRC introduces a hierarchy of geometric perturbations that reorganize the flow field, amplify shear and velocity-gradient fluctuations, and enhance particle–wall interactions. Particle migration exhibits a nonlinear response to roughness due to the competing influences of disturbance amplification and the formation of preferential high-velocity pathways. Furthermore, roughness-controlled scaling relations are identified for mean particle velocity, residence time, and energy dissipation, revealing JRC as a fundamental parameter linking geometric complexity to transport efficiency. Based on these findings, a unified mechanistic framework is established that conceptualizes fractal roughness as a multiscale geometric forcing mechanism governing hydrodynamic heterogeneity, particle dynamics, and dissipative processes. This framework provides new physical insight into transport behavior in rough fractures and offers a scientific basis for improved prediction of clogging, proppant placement, and transmissivity evolution in subsurface engineering applications. Full article

Coalbed methane development is constrained by reservoir characteristics including high gas adsorption, high salinity, and high closure pressure, which impose significant limitations on conventional polymer fracturing fluids regarding viscosity enhancement, proppant transport, and fracture maintenance. In this study, a novel polymer fracturing fluid system, Z-H-PAM, was designed and synthesized to achieve strong salt tolerance, low adsorption affinity, and high elasticity to withstand closure pressure. This was accomplished through the molecular integration of a zwitterionic monomer ZM-1 and a hydrophobic associative monomer HM-2, forming a unified structure that combines rigid hydrated segments with a hydrophobic elastic network. The results indicate that ZM-1 provides a stable hydration layer and low adsorption tendency under high-salinity conditions, while HM-2 contributes to a high-storage-modulus, three-dimensional physically cross-linked network via reversible hydrophobic association. Their synergistic interaction enables Z-H-PAM to retain viscoelasticity that is significantly superior to conventional HPAM and to achieve rapid structural recovery in high-mineralization environments. Systematic evaluation shows that this system achieves a static sand-suspension rate exceeding 95% in simulated flowback fluid, produces broken gel residues below 90 mg/L, and results in a core damage rate of only 10.5%. Moreover, it maintains 88.8% of its fracture conductivity under 30 MPa closure pressure. Notably, Z-H-PAM can be prepared directly using high-salinity flowback water, maintaining high elasticity and sand-carrying capacity while enabling fluid recycling and reducing reservoir damage. This work clarifies the multi-scale mechanisms of strongly hydrated and highly elastic polymers in coalbed methane reservoirs, offering a theoretical and technical pathway for developing efficient and low-damage fracturing materials. Full article

Hydraulic fracturing is a key technique for creating complex fractures in unconventional reservoirs to enhance energy recovery. Asymmetric branched fractures, as fundamental units, are widely observed in complex fracture networks. Effective proppant distribution within such structures is critical but remains poorly understood. To investigate this, a rough-walled slot with two branches was developed, where asymmetry was introduced by inserting plates with different geometries on one side. The results show that the structural asymmetry between the left and right branches can significantly induce non-uniform transport and irregular sand bed morphology. Reducing the height and width of branch fractures increases fluid velocity, limiting proppant settling within the branch. As the flow area decreases, the fluid velocity increases, driving more proppant through the branch toward the distal fracture region. Injection pressure increases as the flow area of the branch fracture decreases. At a height ratio of 0.25, sand plugging and ineffective proppant placement probably occur within the natural fracture. When the branch is located at the upper section, proppants hardly settle to form a bed, leading to closure of the fracture. The study provides new insights into optimizing proppant placement in complex fractures. Full article

With the increasing exploration and development of deep shale gas resources, water-based fracturing fluids face multiple challenges, including high-temperature resistance, salt tolerance, and efficient proppant transport. In this study, a zwitterionic polymer (polyAMASV) is synthesized via aqueous two-phase dispersion polymerization, using acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylic acid (AA), stearyl methacrylate (SMA), and 4-vinylpyridine propylsulfobetaine (4-VPPS) as monomers. The introduction of hydrophobic alkyl chains effectively adjusts the viscoelasticity of the emulsion, while the incorporation of zwitterionic units provides salt tolerance through their intrinsic anti-polyelectrolyte effect. As a result, the solutions of such copolymers exhibit stable apparent viscosity in both NaCl and CaCl₂ solutions and under high temperatures. Meanwhile, polyAMASV outperforms conventional samples across various saline environments, reducing proppant settling rates by approximately 20%. Moreover, the solutions exhibit rapid gel-breaking and low residue characteristics, ensuring effective reservoir protection. These results highlight the promising potential of polyAMASV for deep shale gas fracturing applications. Full article

To address critical limitations of ultra-low viscosity supercritical CO₂ fracturing fluids, including excessive fluid loss and inadequate proppant transport capacity, a series of thickeners designed to significantly enhance CO₂ viscosity were synthesized. Initially, FT-IR and ¹H NMR characterization confirmed successful chemical reactions and incorporation of both solvation-enhancing and -thickening functional groups. Subsequently, dissolution and thickening performance were evaluated using a custom-designed high-pressure vessel featuring visual observation capability, in-line viscosity monitoring, and high-temperature operation. All thickener systems exhibited excellent solubility, with 5 wt% loading elevating CO₂ viscosity to 3.68 mPa·s. Ultimately, molecular simulations performed in Materials Studio elucidated the mechanistic basis, electrostatic potential (ESP) mapping, cohesive energy density analysis, intermolecular interaction energy, and radial distribution function comparisons. These computational approaches revealed dissolution and thickening mechanisms of polymeric thickeners in CO₂. Full article

To address the challenges of low permeability, high gas adsorption, and a fragile structure in coalbed methane reservoirs, this study developed a high-strength composite proppant with an activated carbon skeleton via nitric acid pretreatment, silica–alumina sol coating, and calcination. Orthogonal experiments optimized the preparation conditions: 30–40 mesh activated carbon, Si/Al molar ratio of 4:1, calcination at 650 °C for 2 h. The resulting proppant exhibited an excellent performance: a single-particle compressive strength of 55.5 N, porosity of 33.2%, crushing rate of only 2.3% under 50 MPa closure pressure, and permeability 48.5% higher than quartz sand. In simulated acidic coalbed environments (pH 3–5), its acid corrosion rate was <2.8%, and it enhanced methane desorption by 16.2% compared to pure coal. Additionally, the proppant showed a superior transport performance in fracturing fluids, with better distribution uniformity in fractures than ceramsite, and its hydrophobic surface (contact angle 115.32°) improved fracturing fluid flowback efficiency. This proppant integrates high strength, good conductivity, gas desorption promotion, and corrosion resistance, offering a novel material solution for efficient coalbed methane extraction. Full article

Effective proppant transport is critical to the success of hydraulic fracturing, particularly when using a non-Newtonian fluid. However, accurately predicting the proppant settling behavior under complex rheological conditions is still a significant challenge. This study proposes a new method for estimating the velocity of proppant settling in the power-law non-Newtonian fluid by accounting for spatial variations in viscosity within the fracture domain. The local shear rate field is first obtained using an analytical expression derived from the velocity gradient, and then used to approximate spatially varying viscosity based on the power-law rheological model. This allows the modification of Stokes’ law, which was initially developed for Newtonian fluid, to be used for the power-law non-Newtonian fluid. The results indicate that the model achieved high accuracy in the fracture center region, with an average relative error of 8.2%. The proposed approach bridges the gap between traditional settling models and the non-Newtonian behavior of the fracturing fluid, offering a practical and physically grounded framework for predicting the velocity of proppant settling within a hydraulic fracture. By considering the distribution of the shear rate and viscosity of the fracturing fluid, this method enables an accurate prediction of proppant settling velocity, which further provides theoretical support to the optimization of pumping schedules and operation parameters for hydraulic fracturing. Full article

In deep shale gas fracturing, the narrow width of micro fractures presents a challenge for conventional proppants (40/70 mesh, 70/140 mesh), which often fail to enter branch fractures, resulting in inadequate effective support volume. To address this, a high-efficiency propping strategy is proposed based on the hybrid use of micro-proppants and conventional proppants. Utilizing a proppant transport experiment device, the effects of proppant size ratios and injection timing on proppant distribution were investigated to determine the optimal design parameters. The results indicate that the 200/400 mesh micro-proppant can effectively enter the distal micro fractures, thereby mitigating the problem of the non-uniform distribution of the proppant within the fracture network. To ensure effective propping of secondary fractures, the optimal pumping sequence is to inject quartz sand first, followed by ceramic proppants. The recommended ratio of 70/140 mesh quartz sand to 40/70 mesh ceramic proppants is 7:3. Additionally, for blended injection, the optimal mixing ratio of 70/140 mesh quartz sand to micro-proppant is 8:2. Field trials at the L-X1 well in the LZ block demonstrate that this strategy significantly boosts post-fracturing production, with test yields increasing 2.4 to 4 times. Full article

With growing reliance on hydraulic fracturing to develop tight oil and gas reservoirs characterized by low porosity and permeability, optimizing proppant transport and placement has become critical to sustaining fracture conductivity and production. However, how fracture geometry influences proppant distribution under varying field conditions remains insufficiently understood. This study employed computational fluid dynamics to investigate proppant transport and placement in hydraulic fractures of which the aperture tapers linearly along their length. Four taper rate models (δ = 0, 1/1500, 1/750, and 1/500) were analyzed under a range of operational parameters: injection velocities (1.38–3.24 m/s), sand concentrations (2–8%), proppant particle sizes (0.21–0.85 mm), and proppant densities (1760–3200 kg/m³). Equilibrium proppant pack height was adopted as the key metric for pack morphology. The results show that increasing injection rate and taper rate both serve to lower pack heights and enhance downstream transport, while a higher sand concentration, larger particle size, and greater density tend to raise pack heights and promote more stable pack geometries. In tapering fractures, higher δ values amplify flow acceleration and turbulence, yielding flatter, “table-top” proppant distributions and extended placement lengths. Fine, low-density proppants more readily penetrate to the fracture tip, whereas coarse or dense particles form taller inlet packs but can still be carried farther under high taper conditions. These findings offer quantitative guidance for optimizing fracture geometry, injection parameters, and proppant design to improve conductivity and reduce sand-plugging risk in tight formations. These insights address the challenge of achieving effective proppant placement in complex fractures and provide quantitative guidance for tailoring fracture geometry, injection parameters, and proppant properties to improve conductivity and mitigate sand plugging risks in tight formations. Full article

Aiming at the problem that conventional friction reducers used in fracturing cannot simultaneously possess properties such as temperature resistance, salt resistance, shear resistance, rapid dissolution, and low damage. Under the design concept of “medium-low molecular weight, salt-resistant functional monomer, supramolecular physical crosslinking aggregation, and enhanced chain mechanical strength”, acrylamide, sulfonic acid salt-resistant monomer 2-acrylamide-2-methylpropanesulfonic acid, hydrophobic association monomer, and rigid skeleton functional monomer acryloyl morpholine were introduced into the friction reducer molecular chain by free radical polymerization, and combined with the compound suspension technology to develop a new type of multi-functional viscous friction reducer suspension (SAMD), the comprehensive performance of SAMD was investigated. The results indicated that the critical micelle concentration of SAMD was 0.33 wt%, SAMD could be dissolved in 80,000 mg/L brine within 3.0 min, and the viscosity loss of 0.5 wt% SAMD solution was 24.1% after 10 min of dissolution in 80,000 mg/L brine compared with that in deionized water, the drag reduction rate of 0.1 wt% SAMD solution could exceed 70% at 120 °C and still maintained good drag reduction performance in brine with a salinity of 100,000 mg/L. After three cycles of 170 s⁻¹ and 1022 s⁻¹ variable shear, the SAMD solution restored viscosity quickly and exhibited good shear resistance. The Tan δ (a parameter characterizing the viscoelasticity of the system) of 1.0 wt% SAMD solution was 0.52, which showed a good sand-carrying capacity, and the proppant settling velocity in it could be as low as 0.147 mm/s at 120 °C, achieving the function of high drag reduction at low concentrations and strong sand transportation at high concentrations. The viscosity of 1.4 wt% SAMD was 95.5 mPa s after shearing for 120 min at 140 °C and at 170 s⁻¹. After breaking a gel, the SAMD solution system had a core permeability harm rate of less than 15%, while the SAMD solution also possessed the performance of enhancing oil recovery. Compared with common friction reducers, SAMD simultaneously possessed the properties of temperature resistance, salt resistance, shear resistance, rapid dissolution, low damage, and enhanced oil recovery. Therefore, the use of this multi-effect friction reducer is suitable for the development of unconventional oil reservoirs with a temperature lower than 140 °C and a salinity of less than 100,000 mg/L. Full article

The enhancement of proppant conductivity in shale gas fracturing can be effectively achieved through the implementation of coated proppants. After soaking, non-curable viscous resin-coated proppants exhibit progressive viscosity development and spontaneous agglomeration during the transportation phase. Furthermore, upon fracture closure, the formed proppant agglomerates demonstrate significant stability and do not flow back with the fracturing fluid through the wellbore. While contemporary research has mostly focused on proppant coating methodologies, the transportation process of these proppants remains insufficiently investigated. To fill this knowledge gap, a sophisticated migration two-phase flow coupling model was developed utilizing the computational fluid dynamics–discrete element method (CFD-DEM) approach. This model incorporates the bond contact forces between film-coated proppant particles, accounting for their distinctive cementing characteristics during transport. Through comprehensive numerical simulations, the transport properties of film-coated proppants were systematically analyzed. Field application indicated that compared with conventional continuous sand fracturing, the amount of proppant after treatment with viscous resin film was reduced by 35% and the production was increased by about 25–30%. Additionally, the optimization of the field-scale coated proppant transport processes was achieved through the implementation of a lower fracturing displacement combined with staged sand addition. Full article

The petroleum industry seeks to optimize the reuse of flowback and produced water (FPW) in hydraulic fracturing to reduce environmental impacts and costs. This study investigates how controlling divalent cations in FPW influences its rheological properties and proppant carrying capacity, both of which are crucial for efficient fracturing. Synthetic FPW, modified to simulate treated and untreated conditions, was analyzed to determine the impact of gel-based additives such as anionic polyacrylamide-based friction reducers (FRs). Results indicate that removing divalent cations increases relaxation times from 0.12 s in untreated FPW to 1.00 s in a 1 gallon per thousand gallons (gpt) FR solution, demonstrating improved viscoelastic gel characteristics. However, these changes do not significantly increase proppant carrying capacity. Even with relaxation times increasing to 4.5 s at higher FR dosages (3 gpt), the treated FPW still does not achieve the relaxation time observed in FR solutions using deionized (DI) water, which remain above 10 s. The removal of divalent cations from FPW resulted in only minor changes to its shear viscosity, with a modest 15% increase that was not enough to significantly affect the settling velocity of the proppant. Thus, removal of divalent cations can positively influence rheological behavior; it does not necessarily improve proppant transport efficiency in hydraulic fracturing operations. Full article

The influence of various factors, such as the natural properties of rock and in-situ stress conditions, results in uneven and rough fracture surfaces post-hydraulic fracturing. This significantly impacts the transport and placement of proppant within the fracture, thereby affecting the effectiveness of fracture stimulation. This study employs the rectangular wave method to characterize the roughness of fracture wall morphology, detailing the variation of roughness by altering the number and height of micro-protuberances, and constructs a three-dimensional model of rough fractures. The Euler–Euler model is utilized to simulate the placement and transport patterns of proppant within the fracture. Sand banks within the fracture profile are segmented based on proppant concentration, and the dimensionless area of each concentration interval is calculated to analyze the structure of sand banks and the suspension and settling effects of proppant. This research investigates the variation patterns of sand dune structures within fractures characterized by different levels of roughness and morphologies; it also examines the impact of injection velocity and fracturing fluid viscosity on the transport and placement of proppant within rough fractures. The findings indicate that the complex spatial structure of rough fractures modifies the edge shape of sand dunes. Moreover, it impedes proppant transport, leading to the formation of sand plugs near the wellbore. The maximum distance of sand placement for rough fractures is only 55.2% of that for fractures without considering roughness. The increase in the number and height of micro-protrusions enhances fracture roughness, leading to a stronger retarding effect. However, variations in these two types of roughness have distinct impacts on the morphology of sand dunes. Higher injection velocities facilitate the transport of proppant within rough fractures. The furthest distance of proppant placement at an injection velocity of 0.5 m³/min is only 68.4% of that at an injection velocity of 1.5 m³/min. The study’s findings contribute to a more intuitive understanding of the impact of rough fracture wall surfaces on the transport and placement patterns of proppant, providing a foundation for the optimization of fracturing design and operational parameters. Full article

Hydraulic fracture stimulation is one of the most effective methods to recover oil and gas from unconventional resources. In recent years, foam-based fracturing fluids have been increasingly studied to address the limitations of conventional slickwater such as high water and chemical consumption, environmental concerns, and high incompatibility with water-sensitive formations. Due to the gradual breakdown of liquid foams at reservoir conditions, the combination of silica nanoparticles (SNP) and surfactants has attracted a lot of attention to improve liquid foams’ characteristics, including their stability, rheology, and proppant-carrying capacity. This paper investigates and compares the effects of cationic and anionic surfactants on the fracturing performance of SNP-stabilized foams at the reservoir temperature of 90 °C. The experimental results of viscosity measurements were imported into a 3D fracture-propagation model to evaluate the effectiveness of fracturing foams in transporting and distributing proppants in the fracture system. At both ambient and elevated temperatures, cationic surfactant was experimentally found to have better synergistic effects with SNP than anionic surfactant in improving the apparent viscosity and proppant-carrying capacity of foams. The simulation results demonstrate that fracturing with cationic surfactant-SNP foam delivers greater performance with larger propped area by 4%, higher fracture conductivity by 9%, and higher cumulative gas production by 13%, compared to the anionic surfactant-SNP foam. This research work not only helps validate the interrelationship between fluid viscosity, proppant settlement rate, and fracture effectiveness, but it also emphasizes the importance of proppant placement in enhancing fracture conductivity and well productivity. Full article

The drilling fluid loss or lost circulation via near-wellbore fractures is one of the most critical problems in the drilling of deep oil and gas resources, which causes other problems such as difficulty in achieving wellbore pressure control and reservoir damage. The conventional treatment is to introduce granular lost circulation material (LCM) into the drilling fluid to plug the fractures. As the migration mechanism of the LCM in irregular fractures has not been completely figured out as of yet, the low success rate of fracture plugging and repeated drilling fluid loss still obstruct the exploitation of deep oil and gas resources. In this paper, the spatial data of actual rock fracture surfaces were obtained through structured light scanning, and an irregular surface identical to the rock was machined on a transparent polymethyl methacrylate plate. On this basis, a visualization experimental apparatus for fracture plugging was established, and the fracture flow space of this device was consistent with that of the actual rock fracture. Employing cylindrical nylon particles as LCM, a visualization experiment study was carried out to investigate the process of LCM bridging and fracture plugging and the influence of LCM injection methods. The experimental results show that the process of fracture plugging includes the sporadic bridging, plugging zone extension and merging, thickening of the plugging zone and complete plugging of the fracture. It was observed in the visualization experiment that a large number of small particles flow deep into the fracture in the traditional fracture plugging method, where all types and sizes of LCM are injected at one time. After changing the injection sequence, which injects the large particles first and the small particles subsequently, it is found that the large particles will form single-particle bridging at a specific depth of the fracture, intercepting subsequently injected particles and thickening the plugging zone, which finally increases the area of the plugging zone by 19%. The visualization experiment results demonstrate that modifying the LCM injection method significantly enhances both the LCM utilization rate and the fracture plugging effect, thereby reducing reservoir damage. This is conducive to reducing the drilling cost of fractured formation. Additionally, the visualized experimental approach introduced in this study can also benefit other research areas, including proppant placement and solute transport in rock fractures. Full article