Fracture Flow Research Articles

Relative permeabilities for two-phase flow through wellbore cement fractures

Multiple fluids are likely to exist in fractures and flow paths associated with leaky wellbores, including liquids (e.g., crude oil) and gases (e.g., gas exsolved from liquid). These fluids occupy and move through different portions of the pore spaces within the fractures depending on many factors, including fluid properties, fracture size, and the amount of the different fluids. Upward leakage of any phase, through the fracture, can contaminate water-bearing formations, create hazardous surface conditions, and compromise the functionality of the wellbore. Early signs of wellbore leaks may be expressed by anomalous pressure behavior at surface monitoring points on cavern storage wells. These pressure anomalies are difficult to interpret, necessitating knowledge of the factors that affect the multiphase flow in fractures and porous media. These parameters are critical to modeling multiphase flow in fractures. This insight can guide further diagnosis and maximize leak remediation. Our study focuses on the relationship of the liquid–gas relative permeabilities for representative variable-aperture wellbore cement fracture. To obtain the relative permeability of each phase, two-phase flow tests were conducted where both fluids were flowing simultaneously through a fractured wellbore cement specimen under a range of factors, namely (1) aperture size, (2) capillary numbers, and (3) viscosity ratio. The flow experiments were conducted under a range of confining stresses and flow velocities, using nitrogen gas and silicone oils (of different viscosities) in a specially designed pressure vessel. The sum of gas and oil relative permeabilities were found to be less than one under all conditions, which indicates that the presence of one phase affects the permeability of the other phase, and vice versa. Since the gas phase flow conditions include a significant inertial flow component in addition to viscous flow, the inertial flow coefficients at different saturation states are presented. The factors affecting the relationship between the relative permeabilities are discussed in detail. A new mathematical model for estimating the relative permeability of wellbore cement fracture is presented and experimentally validated.

Geologic and Tectonic Controls on Deep Fracturing, Weathering, and Water Flow in the Central California Coast Range

AbstractThe creation of fractures in bedrock dictates water movement through the critical zone, controlling weathering, vadose zone water storage, and groundwater recharge. However, quantifying connections between fracturing, water flow, and chemical weathering remains challenging because of limited access to the deep critical zone. Here we overcome this challenge by coupling measurements from borehole drilling, groundwater monitoring, and seismic refraction surveys in the central California Coast Range. Our results show that the subsurface is highly fractured, which may be driven by the regional geologic and tectonic setting. The pervasively fractured rock facilitates infiltration of meteoric water down to a water table that aligns with oxidation in exhumed rock cores and is coincident with the adjacent intermittent first‐order stream channel. This work highlights the need to incorporate deep water flow and weathering due to pervasive fracturing into models of catchment water balances and critical zone weathering, especially in tectonically active landscapes.

Research on particle migration in fractures driven by gas-liquid two-phase flow during deep energy storage and extraction

Particle-laden fluid flow in fracture encompasses various deep geo-energy projects, including but not limited to hydraulic fracturing, mud and water inrush, and sand production. The migration of particles under fluid flow seriously affects the stability of geo-energy engineering and understanding the mechanisms is of great importance. This study presents a numerical investigation of particle-laden fluid flow in rock fractures under two-phase flow. A coupled approach of resolved computational fluid dynamics (CFD) and discrete element method (DEM) is employed to capture the particle movements and variations in hydraulic properties, with the volume of fluid (VOF) method to reproduce the two-phase flow. The results indicate that the model with gas injection exhibits higher particles migration velocity compared to that without gas due to the increase in fluid velocity and fluctuation in drag force. Particles migration velocity presents an initial increase followed by a subsequent decrease as the gas fraction increases, which can be attributed to the initial rise followed by a subsequent decline in the drag force. In addition, the sensitive analysis shows that the particle migration velocity decreases with the increase of liquid viscosity and fracture roughness in the fluid, and further accelerates with the increase of particle size and hydraulic gradient. Our results have important implications for understanding the mechanisms of particle migration in rock fractures driven by the multiphase flow during deep energy storage and extraction.

Direct numerical simulations of immiscible two-phase flow in rough fractures: Impact of wetting film resolution

Direct numerical simulations of immiscible two-phase flow in rough fractures: Impact of wetting film resolution

Combined effects of the roughness, aperture, and fractal features on the equivalent permeability and nonlinear flow behavior of rock fracture networks

The hydraulic properties of a fractured rock mass are largely controlled by connected fracture networks. A thorough understanding of the physical flow processes in fracture networks is essential for assessing the transport capacity of the rock mass. However, the fracture surface roughness morphology, fracture distribution characteristics, and fluid flow regimes strongly influence the flow capacity of a fracture network. To this end, the rough topographic characteristics of fracture surfaces were quantified using fractal theory, and then the effective permeability model and nonlinear seepage effect assessment model of the rough fracture network for different flow regimes were developed based on the possible occurrence of laminar and turbulent flows in a single fracture. Finally, the influences of the geometric parameters of the fracture network on the effective permeability and nonlinear flow characteristics were analyzed. The results show that the prediction results of the proposed models are in good agreement with the field test data and can effectively reveal the seepage influence mechanisms under different flow regimes. Additionally, the results show that the effective permeability is closely related to the fractal dimension, relative roughness, aperture scale, distribution characteristics, and hydraulic gradient of the fractures. The nonlinear behavior of fluid flow significantly reduces the effective permeability of the rock mass. The proposed models can provide a reference for evaluating the transport capacity of rock masses under different fracture distributions and flow regimes.

Partially Saturated Fracture‐Matrix Infiltration in Experiments and Theory

AbstractFractures provide pathways for preferential flow, whereas porous rock acts as storage that delays fluid propagation through matrix imbibition. These dual‐porosity mechanisms are investigated in laboratory experiments of partially saturated fracture infiltration. We analyze flow dynamics in terms of the fluid penetration depth in the fracture and delineate fracture‐ and matrix‐dominated flow regimes at different flow rates. We compare wetting front propagation in fracture and matrix and examine the interference of matrix‐wetting fronts with the lateral system boundary. The experimental data are interpreted using the analytical model of Nitao (1991), which accounts for the impact of fracture‐matrix interactions on fluid propagation in the fracture. We find that matrix imbibition affects the observed discontinuous, partially saturated fracture flow to behave, on average, like plug flow. Consequently, and within the range of applied flow rates above a critical threshold, the model’s plug flow assumption is not a relevant precondition for its applicability. Fluid propagation in the fracture exhibits three characteristic scaling regimes (FP1‐3) corresponding to the matrix imbibition state. Only two scaling regimes are established for flow rates below a critical threshold, hence required to recover bulk infiltration for the chosen geometry. Furthermore, wetting fronts switch from fracture‐to matrix‐dominated at moderate to high flow rates, indicating a flow‐rate‐dependent limitation of fracture‐dominated infiltration depth. While the scaling regimes agree with experiments for applied flow rates above the critical threshold, the model underestimates the initial penetration depth below. Here, we observe the direct onset of flow regime FP2 and the delayed transition into FP3.

A Hybrid Prediction Model for Rock Reservoir Bank Slope Deformation Considering Fractured Rock Mass Parameters

Deformation monitoring data provide a direct representation of the structural behavior of reservoir bank rock slopes, and accurate deformation prediction is pivotal for slope safety monitoring and disaster warning. Among various deformation prediction models, hybrid models that integrate field monitoring data and numerical simulations stand out due to their well-defined physical and mechanical concepts, and their ability to make effective predictions with limited monitoring data. The predictive accuracy of hybrid models is closely tied to the precise determination of rock mass mechanical parameters in structural numerical simulations. However, rock masses in rock slopes are characterized by intersecting geological structural planes, resulting in reduced strength and the creation of multiple fracture flow channels. These factors contribute to the heterogeneous, anisotropic, and size-dependent properties of the macroscopic deformation parameters of the rock mass, influenced by the coupling of seepage and stress. To improve the predictive accuracy of the hybrid model, this study introduces the theory of equivalent continuous media. It proposes a method for determining the equivalent deformation parameters of fractured rock mass considering the coupling of seepage and stress. This method, based on a discrete fracture network (DFN) model, is integrated into the hybrid prediction model for rock slope deformation. Engineering case studies demonstrate that this approach achieves a high level of prediction accuracy and holds significant practical value.

Estimation of Effective Fracture Aperture in Glacial Tills by Analysis of Dye Tracer Penetration.

This study advances a methodology to estimate effective apertures of fractures in glacial tills based on dye tracer infiltration tests and numerical simulations. The approach uses the visible penetration depth of the dye tracer along fracture flow paths as primary information to calculate effective fracture apertures. Further data used in the calculation are the dye tracer input concentration and retardation, the duration of the tracer injection, and the hydraulic gradient applied to control the infiltrating water fluxes. The method does not require measurement of hydraulic conductivity for the fractured till and enables direct observation of flow and transport patterns within the fractures (e.g., uniform flow and dye tracer distribution, channeling due to aperture variability, and presence of biogenic macropores in fractures). The approach was successfully verified by using the estimated effective fracture aperture values in Large Undisturbed Columns (LUCs) to consistently simulate both the observed LUC effluent breakthrough of a conservative bromide tracer and the water fluxes with the hydraulic gradient applied in the experiments. Sensitivity analyses revealed that estimation of small effective fracture apertures (<10 μm) required accurate determination of the dye tracer retardation factor. By contrast, in the case of larger effective apertures (>20 μm), the sensitivity of the estimated effective fracture aperture to variations in the porous material and solute transport parameters was low compared to the dominant sensitivity to the water flow through the fractures (cubic relation between flow and aperture). The proposed approach may be extended beyond laboratory applications and assist in characterizing field-scale fracture networks.

Steady-state relative permeability measurements in rough-walled fractures: The effects of wettability and aperture

Tight subsurface geosystems provide significant prospects for the recovery and storage of mass and energy. Because of the tightness of these systems, natural and engineered fractures are the main conveyance conduits transporting the fluids from the tight rock matrix to the wellbore or vice versa. During the fracturing process, most of the newly induced fractures are considered water-wet, however during injection/production, the wettability of the fractures gradually changes. These changes are mainly due to the interactions between the resident and injected fluids, or the exposure of the virgin fracture surfaces to the resident fluids during production. This alteration in wettability can affect the trapping and flow dynamics, e.g., relative permeability, of the fluids flowing in the fracture. Furthermore, fluid injection and production into and from these systems impact the fractures pore pressure and hence the effective stress they are exposed to, resulting in variations in the fracture aperture. In this study, we present a comprehensive macro-scale experimental investigation focusing on the impact of wettability and aperture on steady-state two-phase relative permeability in rough-walled fractures. Using the stead-state measurement technique, we meticulously characterized oil-brine relative permeabilities and residual trapping in water-wet, oil-wet, and mixed-wet rough-walled fractures induced in Eagle Ford shale rock samples. Additionally, we assessed the influence of fracture aperture size on these properties during both drainage and imbibition flow processes. Our results indicate significant phase interference in oil-brine flow in non-water-wet rough-walled fractures, which renders the commonly used x-curve and Corey models inadequate to represent the steady-state oil-brine relative permeabilities measured in our study, leading to substantial overestimations. Mixed-wet fractures exhibited reduced relative permeabilities compared to oil-wet fractures, which in turn demonstrated lower relative permeabilities than water-wet counterparts. The observed trends stem from evolving fluid configuration and transport dynamics within the fractures as surface wettability transitions. Furthermore, an increase in fracture aperture corresponded with an increase in relative permeability. This was attributed to a broader flow area, diminished capillarity, attenuated impact of fracture wall roughness and tortuosity effects, and a reduction in bypassing and trapping events, all synergistically contributing to the mitigation of phase interference. Similarly, an increase in fracture aperture led to a marked decrease in post-waterflooding endpoint oil saturation and post-oil flooding endpoint brine saturation. Finally, we provided generalized correlation models based on experimental results from fractures with varying conductivities and wettability, yielding a more accurate representation of fracture relative permeabilities compared to traditional models. The data and correlation models produced in this study improve our understanding and prediction of multiphase flow in subsurface fractures and offer insights into rapid production decline in unconventional shale reservoirs.

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.

Influence of inertial and centrifugal forces on rate and flow patterns in natural fracture networks

Fluid production from fractured rock masses readily induces fracture flow velocities of meters per second. Yet, most discrete fracture flow models treat flow as laminar creeping flow or account for inertia effects only by single-fracture constitutive relationships.This numeric simulation study investigates water flow patterns and spatial velocity variations in a natural fracture network with mm-wide open fractures, studying the transition from laminar creeping to turbulent flow. After verification with a fracture intersection model, a Reynolds-time-averaged Navier Stokes solver serves to analyse flow regimes and velocity distribution. Our results show that for fracture flow velocities greater than ∼1-cm/s, fluid inertia begins to markedly alter flow patterns and the overall velocity distribution in the network. The pressure-gradient-flow relationship therefore becomes non-linear long before the flow in straight fractures enters the weak inertia regime. This prominence of inertia effects highlights the need to improve fracture network flow models.

Evaluation of Lost Circulation Material Sealing for Geothermal Drilling

Lost circulation is a pervasive problem in geothermal wells that can create prohibitive costs during drilling. The main issue with treatment is that the mechanism of plug formation is poorly understood. Here we applied two experimental approaches to characterize the clogging effectiveness of different materials. Fracture flow tests with different geometries were conducted with various individual materials and mixtures at relevant conditions. A high-temperature flow loop system was also developed to inject single- and mixed-material plugs into a gravel pack with a non-uniform geometry to compare with the fracture tests. The fracture tests revealed that single materials tended to form no plug or an unstable plug, while mixtures of materials were uniformly better at sealing fractures. Gravel pack tests at high temperatures show most of the materials are intact but degraded. The fibrous materials can create partial or unstable plugs in the gravel pack, but mixed-material plugs are far more effective at clogging. Both test types suggest that (1) mixed materials are more effective at blocking fluid flow and (2) fibrous materials seal fracture openings better, while granular materials seal inside fractures or pore throats better. Further research is needed to study the long-term stability of different plug configurations.

Pore-scale insights into relative permeability in strongly and weakly wet natural fractures: A Lattice Boltzmann Method 2D simulation study

The simplified view of two-phase flow, such as oil and gas, in a fracture is often assumed to occur in a stratified behavior. However, recent studies and production practices have revealed that two-phase flow in fractures exhibits diverse flow patterns. This paper investigates the control of the fracture aperture, fluids viscosity, and wettability on two-phase flow in a 2D cross section of a 3D Berea fracture. Lattice Boltzmann Method (LBM) simulations are used to model the impact of these properties on relative permeability curves. Notably, in strongly wet fractures, two distinct permeability regimes emerge. High aperture values exhibit behavior resembling parallel planes, while low aperture values lead to a linear decrease in permeability due to fluid interactions between fracture surfaces. Conversely, anomalous behavior of the relative permeability curves is identified in weakly wet fractures within specific aperture ranges. This behavior is associated with the occurrence of specific flow patterns within the fracture. Results also emphasize that changes in viscosity ratio do not affect the presence or the saturation range of the anomalous behavior but do influence its intensity for each fluid. Comparisons with Poiseuille profile equations reveal the limited impact of the fracture roughness. These findings enhance our understanding of the interactions between aperture, viscosity, and wettability and how they control the shape of the relative permeability curves. These curves are pivotal parameters for the continuum scale modeling (reservoir models) in oil and gas application, for instance.

A model for saturated–unsaturated flow with fractures acting as capillary barriers

AbstractHigh‐resolution modeling of the flow dynamics in fractured soils is highly complex and computationally demanding as it requires precise geometrical description of the fractures in addition to resolving a multiphase free‐flow problem inside the fractures. In this paper, we present an idealized model for saturated–unsaturated flow in fractured soils that preserves the core aspects of fractured flow dynamics using an explicit representation of the fractures. The model is based on Richards’ equation in the matrix and hydrostatic equilibrium in the fractures. While the first modeling choice is standard, the latter is motivated by the difference in flow regimes between matrix and fractures, that is, the water velocity inside the fractures is considerably larger than in the soil even under saturated conditions. On matrix/fracture interfaces, the model permits water exchange between matrix and fractures only when the capillary barrier offered by the presence of air inside the fractures is overcome. Thus, depending on the wetting conditions, fractures can either act as impervious barriers or as paths for rapid water flow. Since in numerical simulations each fracture face in the computational grid is a potential seepage face, solving the resulting system of nonlinear equations is a nontrivial task. Here, we propose a general framework based on a discrete‐fracture matrix approach, a finite volume discretization of the equations, and a practical iterative technique to solve the conditional flow at the interfaces. Numerical examples support the mathematical validity and the physical applicability of the model.

Steady-state two-phase relative permeability measurements in proppant-packed rough-walled fractures

Understanding multiphase flow in fractures filled with minerals and proppants is vital in various subsurface applications. Limited experimental data have led to reliance on correlations lacking physical basis. We conducted experiments to characterize relative permeability in rough-walled fractures packed with unconsolidated porous media. We tested fractures packed with water-wet 40/70 sand (silica) and surface-coated ceramic proppants. Brine and mineral oil were used as the wetting and non-wetting fluid phases, respectively. Steady-state (SS) drainage (non-wetting-phase displacing wetting-phase) and imbibition (wetting-phase displacing non-wetting-phase) tests were performed under a wide range of saturation histories (full-cycle and scanning-curves) to study relative permeability hysteresis of the propped fractures. Every SS drainage or imbibition test consisted of several discrete points at which fluid saturations and the corresponding relative permeability were measured by varying the fractional flow rates of fluids whilst maintaining a constant total flow rate. We analyzed residual non-wetting phase saturations and relative permeability trends to understand two-phase flow behavior in each proppant pack. High-resolution x-ray microtomography was used to understand the pore-scale topology, wettability, and to provide insights about the pore-scale displacement mechanisms involved in this study. The results showed that commonly used models to estimate relative permeabilities of fractures significantly overestimated the SS brine and oil relative permeabilities (denoted as krw and kro) measured in this study. Further analysis unveiled that the kro values during imbibition exceeded their drainage counterparts in both proppants, the ceramic proppant exhibited a lower initial water saturation and a higher end-point kro permeability at the end of the drainage displacement, as well as higher krw across all flooding processes. Updated fitting parameters for a Brooks-Corey-type relative permeability correlation are introduced. This study presents improved insights, extensive experimentally generated relative permeability data, and an updated relative permeability correlation, which can be collectively utilized to reduce uncertainties associated with continuum-scale forecasts of multiphase flow behavior in fractured subsurface formations.

The Inversion Method of Shale Gas Effective Fracture Network Volume Based on Flow Back Data—A Case Study of Southern Sichuan Basin Shale

Fracture network fracturing is pivotal for achieving the economical and efficient development of shale gas, with the connectivity among fracture networks playing a crucial role in reservoir stimulation effectiveness. However, flow back data that reflect fracture network connectivity information are often ignored, resulting in an inaccurate prediction of the effective fracture network volume (EFNV). The accurate calculation of the EFNV has become a key and difficult issue in the field of shale fracturing. For this reason, the accurate shale gas effective fracture network volume inversion method needs to be improved. Based on the flow back characteristics of fracturing fluids, a tree-shaped fractal fracture flow back mathematical model for inversion of EFNV was established and combined with fractal theory. A genetic algorithm workflow suitable for EFNV inversion of shale gas was constructed based on the flow back data after fracturing, and the fracture wells in southern Sichuan were used as an example to carry out the EFNV inversion. The reliability of the inversion model was verified by testing production, cumulative gas production, and microseismic results. The field application showed that the inversion method proposed in this paper can obtain tree-shaped fractal fracture network structure parameters, fracture system original pressure, matrix gas breakthrough pressure, fracture compressibility coefficient, reverse imbibition index, equivalent main fracture half length, and effective initial fracture volume (EIFV). The calculated results of the model belong to the same order of magnitude as those of the HD model and Alkouh model, and the model has stronger applicability. This research has important theoretical guiding significance and field application value for improving the accuracy of the EFNV calculation.

Permeabilities of Water–Oil Two-Phase Flow in Capillary Fractures with Different Wettabilities

The influence of wettability on the permeability performance of water–oil two-phase flow has attracted increasing attention. Dispersed flow and stratified flow are two flow regimes for water–oil two-phase flow in capillary fractures. The theoretical models of relative permeability considering wettability were developed for these two water–oil flow regimes from the momentum equations of the two-fluid model. Wettability coefficients were proposed to study the impact of wettability on relative permeabilities. Experiments were conducted to study the relative permeabilities of laminar water–oil two-phase flow in water-saturated and oil-saturated horizontal capillary fractures with different hydraulic diameters. These fractures were made of polymethylmethacrylate (PMMA) and polytetrafluoroethylene (PTFE), which had different surface wettabilities. In this experiment, the regimes are dispersed flow and stratified flow. The results show that the effect of wettability on the relative permeabilities increases as the hydraulic diameters of capillary fractures decrease for water–oil two-phase flow. The relative permeabilities in a water-saturated capillary fracture are higher than those in an oil-saturated capillary fracture of the same material. The relative permeabilities in a PTFE capillary fracture are larger than those in a PMMA capillary fracture under the same saturated condition. Wettability has little effect on the permeability performances of water–oil two-phase flow in water-saturated capillary fractures, but is significant for those in oil-saturated capillary fractures.

Quantifying flow regime impacts on hydrodynamic heat transfer in rough-walled rock fractures

Hydrodynamic heat transfer in rock fractures is crucial for many geophysical processes and engineering activities, notably in harnessing geothermal energy. Despite extensive research, characterizing hydrodynamic heat transfer in rock fractures, complicated by their geometric heterogeneity, remains a formidable challenge. To address this challenge, we experimentally investigated the hydrodynamic heat transfer in rock fractures with diverse geometric features at steady-state elevated temperatures. We found that both heterogeneous fracture geometry and elevated temperatures promote the transition of fracture flow from a linear to nonlinear regime. This flow regime transition enhances the heterogeneity of heat transfer intensity within the fracture and exacerbates the increase in heat transfer efficiency with flow rate. At a fortyfold increase in flow rate, the heat transfer coefficient in the most heterogeneous fracture rises by approximately 72 times, compared to about 28 times in the least heterogeneous one. Leveraging experimental data, we developed parametric models linking heat transfer coefficients, outflow temperature, and heat recovery rate to flow rate and geometric features, yielding a theoretical formulation for the maximal heat recovery rate. By introducing the concept of an energy conversion rate, we quantitatively evaluated the effect of nonlinear flow resistance on heat extraction feasibility, revealing that energy conversion rates in highly heterogeneous fractures can be up to 452 times lower than in less heterogeneous ones. This highlights the pivotal role of flow resistance in heat extraction feasibility. Our findings are instrumental for understanding and predicting the hydrodynamic heat transfer within fractured geothermal reservoirs and analogous hydro-thermal systems.

Effects of natural fracture reopening on proppant transport in supercritical CO2 fracturing: A CFD-DEM study

The reopening of natural fractures reshapes the proppant beds in hydraulic fractures, especially at fracture intersections, critically influencing subsequent proppant migration. However, studies on the effects of proppant bed shapes on post-reopening proppant migration are limited. To address this gap, a moving wall boundary technique is integrated into a Computational Fluid Dynamics–Discrete Element Method (CFD-DEM) framework to model natural fracture reopening, enabling an in-depth analysis of how proppant bed reshaping impacts subsequent proppant migration during supercritical CO2 fracturing. Results reveal that proppant migration into natural fractures is governed by both drag force-induced and gravity-induced rolling mechanisms, with the latter exerting a more significant effect. The gravity-induced rolling mechanism is enhanced by five key factors: (a) the generation of a well-developed proppant pack in proximity to the intersection; (b) the inadequately filled V-shaped gully; (c) the increased proppant transport capacity within the natural fracture; (d) the reduced bypassing of proppants at the intersection; and (e) the improved ability of proppants to enter the natural fracture. The enhanced gravity-induced rolling mechanism significantly increases the proppants flowing into natural fractures: by 35.6% between the central and rearward section cases, 168.9% from mild to severe plugging cases, 39.1% with a wider natural fracture width (1.5 mm–2.5 mm), 20.3% with decreased hydraulic fracture flow rate (0.35 m/s to 0.25 m/s), and 33% with reduced fluid temperature (160 °C–40 °C). These findings underscore the impact of natural fracture reopening on subsequent proppant migration, offering valuable insights for optimizing fracturing designs.

Experimental investigation on nonlinear flow and solute transport behavior in interlayer expansion fractures

Experimental investigation on nonlinear flow and solute transport behavior in interlayer expansion fractures