Permeability Of Fracture Network Research Articles

Impact of stress regime change on the permeability of a naturally fractured carbonate buildup (Latemar, the Dolomites, northern Italy)

Abstract. Changing stress regimes control fracture network geometry and influence porosity and permeability in carbonate reservoirs. Using outcrop data analysis and a displacement-based linear elastic finite-element method, we investigate the impact of stress regime change on fracture network permeability. The model is based on fracture networks, specifically fracture substructures. The Latemar, predominantly affected by subsidence deformation and Alpine compression, is taken as an outcrop analogue for an isolated (Mesozoic) carbonate buildup with fracture-dominated permeability. We apply a novel strategy involving two compressive boundary loading conditions constrained by the study area's NW–SE and N–S stress directions. Stress-dependent heterogeneous apertures and effective permeability were computed in the 2D domain by (i) using the local stress state within the fracture substructure and (ii) running a single-phase flow analysis considering the fracture apertures in each fracture substructure. Our results show that the impact of the modelled far-field stresses at (i) subsidence deformation from the NW–SE and (ii) Alpine deformation from N–S increased the overall fracture aperture and permeability. In each case, increasing permeability is associated with open fractures parallel to the orientation of the loading stages and with fracture densities. The anisotropy of permeability is increased by the density and connectedness of the fracture network and affected by shear dilation. The two far-field stresses simultaneously acting within the selected fracture substructure at a different magnitude and orientation do not necessarily cancel each other out in the mechanical deformation modelling. These stresses affect the overall aperture and permeability distributions and the flow patterns. These effects – potentially ignored in simpler stress-dependent permeability – can result in significant inaccuracies in permeability estimation.

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.

Numerical Simulations of Viscous Fingering in Fractured Porous Media

AbstractThe effect of heterogeneity induced by highly permeable fracture networks on viscous miscible fingering in porous media is examined using high-resolution numerical simulations. We consider the planar injection of a less viscous fluid into a two-dimensional fractured porous medium that is saturated with a more viscous fluid. This problem contains two sets of fundamentally different preferential flow regimes; the first is caused by the viscous fingering, and the second is due to the permeability contrasts between the fractures and the rock matrix. We study the transition from the regime where the flow is dominated by the viscous instabilities, to the regime where the heterogeneity induced by the fractures define the flow paths. Our findings reveal that even minor permeability differences between the rock matrix and fractures significantly influence the behavior of viscous fingering. The interplay between the viscosity contrast and permeability contrast leads to the preferential channeling of the less viscous fluid through the fractures. Consequently, this channeling process stabilizes the displacement front within the rock matrix, ultimately suppressing the occurrence of viscous fingering, particularly for higher permeability contrasts. We explore three fracture geometries: two structured and one random configuration and identify a complex interaction between these geometries and the development of unstable flow. While we find that the most important factor determining the effect of the fracture network is the ratio of fluid volume flowing through the fractures and the rock matrix, the exact point for the cross-over regime is dependent on the geometry of the fracture network.

Influence of non-intersecting cemented natural fractures on hydraulic fracture propagation behavior

Fractures in deeply buried or formerly deeply buried rocks commonly contain mineral deposits having varying degrees of strength. Understanding how cement deposits in fractures interact with hydraulic fractures (HFs) is important for hydraulic fracture design for practical engineering applications such as enhanced geothermal fluid circulation or oil and gas production. Using discrete element methods, we describe a fully fluid-solid coupling numerical model simulating hydraulic fracture propagation to investigate the influence of cemented natural fractures (CNFs) that do not intersect the predicted path of hydraulic fractures on HF propagation morphology. The fracture morphology depicted by the numerical model aligns well with analytical solutions, indicating the reliability of the simulation results. Using this model, we delved into the effects of fracture cement strength and position, fracturing fluid viscosity, and induced stress field on the interactive propagation patterns of fractures. The simulation results indicate that the HF is captured by weakly non-intersecting CNF, causing the activation of the CNF and the development of cracks primarily caused by tensile failure. As the HF approaches the CNF, the induced tensile stress region at the fracture tip offsets toward the CNF, resulting in fracture reorientation. When the cementing strength ratio between pre-existing natural fracture and reservoir matrix is less than 0.5, it is beneficial to activate CNF and enhance reservoir permeability. The seepage of low-viscosity fracturing fluid into the reservoir significantly enhances the ability of the HF and non-intersecting CNF to communicate with each other, thereby providing favorable pathways for oil and gas flow. The research findings offer valuable insights into fracture network connectivity and permeability enhancement, contributing to enhanced reservoir stimulation strategies.

Investigating rough single-fracture permeabilities with persistent homology

Abstract. The permeability of rock fractures is a crucial parameter for flow processes in the subsurface. In the last few decades, different methods were developed to investigate on permeability in fractures, such as flow-through experiments, numerical flow simulations, or empirical equations. In recent years, the topological method of persistent homology was also used to estimate the permeability of fracture networks and porous rocks but not for rough single fractures yet. Hence, we apply persistent homology analysis on a decimetre-scale, rough sandstone bedding joint. To investigate the influence of roughness, three different data sets are created to perform the analysis: (1) 200 µm, (2) 100 µm, and (3) 50 µm resolutions. All estimated permeabilities were then compared to values derived by experimental air permeameter measurements and numerical flow simulation. The results reveal that persistent homology analysis is able to estimate the permeability of a single fracture, even if it tends to slightly overestimate permeabilities compared to conventional methods. Previous studies using porous media showed the same overestimation trend. Furthermore, the expenditure of time for persistent homology analysis, as well as air permeameter measurements and numerical flow simulation, was compared, which showed that persistent homology analysis can be also an acceptable alternative method.

Investigation of REV scale and anisotropy for 2D permeable fracture Networks: The role of geological entropy

To investigate the intrinsic association between geometrical properties and permeability of anisotropic fractured media, a methodology of geological entropy is applied to anisotropic fracture networks for the evaluation of seepage fields. By integrating the synthetic effect of fracture geometrical parameters (e.g., trace length, spacing, dip angle, and aperture), the global connectivity of fracture networks is quantified by the entropy scale (Hs), while the directional entropy scale (Hs,α) is used to characterize the local geometrical anisotropy in arbitrary orientations. A series of hydraulic representative elementary volumes (REVs) of fracture patterns with various geometrical properties are acquired based on continuum analysis. The permeability in the continuum scale is obtained from steady-state flow simulations. Sensitivity analyses are performed to understand the geometrical dependence of permeability parameters regarding entropy indices. It is found that a systematic increase in trace length, spacing, and dip angle is correlated with an increase, decrease, and equilibrium in entropy, respectively, which corresponds to a change in hydraulic REV sizes that can be expressed as a power-law function related to the Hs. Moreover, Hs,α can well explain the permeability anisotropy resulting from the spatial order of fracture networks, and a unified mathematical relationship for the effective permeability coefficients in arbitrary orientations versus the Hs,α is proposed, independent of variations in fracture patterns and scales. The results indicate that geological entropy, related to the geometrical properties and spatial distribution of fractures, is appropriate to characterize the permeability of anisotropic systems.

FRACTAL STUDY ON THE INFLUENCE OF SURFACE MORPHOLOGY ON SEEPAGE CHARACTERISTICS IN THE ROUGH FRACTURE NETWORK

In the fracture network, the surfaces of fracture are frequently rough. In this article, a binary tree fractal model for curved capillaries has been established based on the fractal theory. The expression of the mass flux rate of the fluid in the rough fracture network has been derived following the Hagar-Poiseuille formula, and the term of the gas mass flux rate has been obtained by using the gas plane radial flow binomial law. The two have been combined to obtain a fracture network permeability model. The correctness and availability of the model have been demonstrated by comparing it with the experimental data. Furthermore, the sensitivity of the model parameters has been analyzed.

Phase-Field Modeling of Coupled Thermo-Hydromechanical Processes for Hydraulic Fracturing Analysis in Enhanced Geothermal Systems

Abundant geothermal energy can be harvested from deep, low-permeability rocks using an enhanced geothermal system (EGS) that relies on an artificially created permeable fracture network through cold water injection. In this study, a two-way coupling technique for thermo-hydromechanical modeling was used to simulate hydraulic fracture propagation in an EGS. The transient heat and fluid flow in porous media were modeled using the finite volume method, while hydraulic fracture propagation and interaction with natural fractures were modeled using the variational phase-field method. Our findings underscore the importance of poroelastic and thermoelastic effects on fracture propagation in naturally fractured reservoirs. The results of this study demonstrate that thermo-hydromechanical processes are crucial elements in simulating and optimizing an enhanced geothermal reservoir system.

Novel calculation method to predict gas–water two-phase production for the fractured tight-gas horizontal well

The prediction of production capacity in tight gas wells is greatly influenced by the characteristics of gas–water two-phase flow and the fracture network permeability parameters. However, traditional analytical models simplify the nonlinear problems of two-phase flow equations to a large extent, resulting in significant errors in dynamic analysis results. To address this issue, this study considers the characteristics of gas–water two-phase flow in the reservoir and fracture network, utilizes a trilinear flow model to characterize the effects of hydraulic fracturing, and takes into account the stress sensitivity of the reservoir and fractures. A predictive model for gas–water two-phase production in tight fractured horizontal wells is established. By combining the mass balance equation with the Newton–Raphson iteration method, the nonlinear parameters of the flow model are updated step by step using the average reservoir pressure. The accuracy of the model is validated through comparisons with results from commercial numerical simulation software and field case applications. The research results demonstrate that the established semi-analytical solution method efficiently handles the nonlinear two-phase flow problems, allowing for the rapid and accurate prediction of production capacity in tight gas wells. Water production significantly affects gas well productivity, and appropriate fracture network parameters are crucial for improving gas well productivity. The findings of this work could provide more clear understanding of the gas production performance from the fractured tight-gas horizontal well.

Investigation into a perfect matching between fracture transfer performance and vertical well productivity based on multi-scale and total factor characteristic models

In fractured tight gas reservoirs, complex hydraulically induced fracture networks determine fluid flowing abilities of reservoirs. Thus, characterizing the complex fracture networks and revealing fracture transfer performances become a challenging work because of fracture branching, bending, and reversing in fractured reservoirs. In this paper, a fractal-like tree-shaped fracture model for gas transfer is proposed to optimize flow conductivity, pressure distribution at fracture intersection points, and flow transfer in such a complex fracture network considering the multi-scale effect, and total factor characteristics, including the length ratio, width ratio, branching angle, and branching level. The model is implemented to conduct validation against the experiment data in the literature. Subsequently, applying the proposed fracture model, the productivity equation for a vertical gas well intercepted by the fractal-like tree-shaped fracture network is further formulated. In addition, the good match with productivity simulation validates the accuracy of the developed productivity model for a vertical gas well. As a result, the impacts of the Knudsen number, fracture total factor characteristics, reservoir parameters, etc. on fracture transfer performances and well productivity are examined using the two proposed models. The results demonstrate that optimum fracture transfer performances do not match with the maximum well productivity. In contrast, the well productivity is jointly determined by both inlet flow volume of the fracture network and matrix permeability. Hence, a new formula considering both fracture characteristics and reservoir properties is proposed to match with the optimum fracture total length and maximum well productivity, thereby contributing to high-efficient and economic exploration of tight gas reservoirs.

Estimation of rough fracture network permeability using fractal and topology theories

Accurate characterization of the rough fracture network in real rocks is an essential prerequisite for precise estimation of fracture network permeability. The characterization of a fracture network in previous theoretical models is usually based on statistical theory, ignoring the topological characteristics of the real fracture network. In this paper, based on fractal and topological theories, the rough characteristics of real rock fractures are considered, and fracture network branch lengths and connectivity are introduced. A new theoretical prediction equation of fractal permeability for rough fracture networks is derived. Subsequently, the reliability of the proposed theoretical model is verified based on discrete fracture network (DFN) modeling and numerical simulation, and the main influencing factors of the rough fracture network permeability are analyzed. The results show that the rough fracture network permeability theoretical model proposed in this paper can effectively evaluate fractured rock permeability. Connectivity is linearly related to permeability. The better the connectivity of the rough fracture network, the denser the streamlines within the fractured rock and the higher the flow rate. The rough fracture network permeability increases with the increase of connectivity, minimum branch length, maximum branch length, tortuosity, and aperture proportionality coefficient, and decreases with the increase of tortuosity fractal dimension and fracture dip angle. When the branch length ratio lbmin/lbmax is less than 0.2, the larger the fractal dimension of the rough fracture network, the lower the permeability. When the ratio is greater than 0.2, the opposite is true. The sensitivity of the rough fracture network permeability to the fracture dip angle θ and the aperture proportionality coefficient β is higher, while the sensitivity to the fractal dimension Df of the rough fracture network is lower.

A fractal model for estimating the permeability of tortuous fracture networks with correlated fracture length and aperture

Many fractures are present in the crust and dominate fluid flow and mass transport. This study proposes a fractal model of permeability for fractured rock masses that includes fractal properties of both fracture networks and fracture surface tortuosity. Using this model, a mathematical expression is derived based on the traditional parallel-plate cubic law and fractal theory. This expression functions as the equivalent permeability of the tortuous fracture network in terms of the maximum fracture length lmax, the fractal dimension of the length distribution Df, porosity ϕ, fracture orientation θ, and the proportionality coefficient between fracture length and aperture β. The fractal scaling law of the fracture length distribution and fractal permeability model is verified by comparison with published studies and fluid dynamic computation, respectively. The results indicate that the deviation of permeability values predicted by the models that do or do not consider the fracture surface tortuosity are as large as three orders of magnitude, which emphasizes that the role of tortuosity should be considered to avoid the overestimation of permeability due to the smooth fracture surface assumption. Further analyses show that the permeability increases with increasing fractal dimension Df, proportionality coefficient β, maximum fracture length lmax, and effective porosity ϕ but decreases with increasing tortuosity dimension Dtf and orientation θ. The fractal dimension of the fracture length distribution Df has the most significant influence on the permeability of the fracture network, followed by Dtf, β, lmax, θ, and ϕ, sequentially.

Finite‐Size Scaling for the Permeability of Discrete Fracture Networks

AbstractWe formulate a finite‐size scaling hypothesis to predict the global permeability of fracture networks. To validate the hypothesis, numerous discrete fracture networks are generated, and the permeability is numerically calculated. Results suggest that the dimensionless permeability, scaled by moments of local conductivity and fracture sizes and corrected by two stereological ratios, can capture variations in fracture attributes (orientations, sizes, and apertures). The universal form obtained in this study can also explain the contradictory observations where the permeability decreases or increases with the domain size of fracture networks. We show that how a clear transition point, where the permeability does not change with the domain size, is obtained from this universal form. This study provides a solid theoretical foundation to understand the connection between fracture attributes and field‐scale hydraulic properties.

Study on coalbed methane flow characteristics based on fractal bifurcation fracture network model

The geometric structure and distribution of the fracture network significantly impact the coalbed methane flow characteristics. The indoor optical microscope test is utilized to analyze the distribution and structural characteristics of natural fractures in coal. The results indicate that the fracture network in coal consists primarily of irregular bifurcated fractures, but the influence of the bifurcation fracture network’s structural characteristics on permeability remains unclear. Therefore, the fracture network geometric structure characteristic parameters are considered in accordance with the fractal theory, and the analytical formula of the bifurcation fracture network permeability is established. Meanwhile, the bifurcation fracture network geometric model with varied structural parameters is reconstructed using the pixel probability decomposition algorithm. Finally, the influence of the key parameters of the reconstructed bifurcation fracture network on the coal seam permeability is analyzed through numerical simulation. The results indicate that the permeability of the bifurcated fracture network increases with the increase of fracture porosity φf, aperture ratio χ, and proportionality coefficient η, and decreases with the increase of tortuosity fractal dimension DT, bifurcation angle θ, fractal dimension Df, and bifurcation level n. Among them, fracture porosity and proportionality coefficient have the greatest influence on permeability, followed by tortuosity fractal dimension, aperture ratio.

A multiscale neural network model for the prediction on the equivalent permeability of discrete fracture network

An equivalent permeability approach can upscale the discrete fracture network (DFN) model to an equivalent DFN model and significantly reduce the gas flow simulations in a large-scale fractured gas reservoir. Current equivalent permeability prediction models are only applicable to the reservoir with a simple fracture network. However, an equivalent permeability prediction model has not been available for a reservoir with a multiscale discrete fracture network. This study proposes a multiscale convolutional neural network model (called MsNet) and introduces three mainstream structures with high performance convolutional neural network (CNN) (ResNet-18, VGG-16 and GoogLeNet) to efficiently predict the equivalent permeability of a complex multiscale fracture network. These CNN models use both the images and features of DFN as their input and the equivalent permeability as their output. This MsNet model is validated with the simulation results simulated by Lattice Boltzmann method and compared with the three mainstream CNN structures and an existing permeability prediction model (CNN-4). It is found that this MsNet model innovatively considers the multiscale characteristics of DFN by a multiscale convolution feature fusion and combines the residual connection for further performance enhancement. Both DFN dataset and MsNet model structure affect the model prediction ability. A deeper network structure of MsNet model can enhance its prediction ability, but significantly increases training time. The MsNet-8-4 (a MsNet structure with 8 multiscale connection modules and 4 sub-networks in each module) has the least convergence time and the lowest mean absolute error on the test set. It performs obviously better than other four models on the DFN dataset with higher fracture density. The MsNet model can well accelerate the simulation on the gas flow in a complex discrete fracture network.

An image-based coal network model for simulating hydro-mechanical gas flow in coal: An application to carbon dioxide geo-sequestration

CO2 geo-sequestration is a practical approach to achieve net-zero carbon target. However, one of the main challenges for successful CO2 geo-sequestration is the reduced coal permeability and injectivity that are caused by coal swelling. Coal has complex and heterogenous internal pore and fracture structure. The processes of gases adsorbing, desorbing, and transporting within multiscale heterogeneous coal structures are more complicated compared with conventional rocks. This paper aims to gain insights about the gas transport behaviours in coal by developing a coupled model to simulate gas flow multiphysics as well as dynamic coal deformation. This work develops an image-based 3D fracture network model, called Fracture Box Model (FBNM). In this model, each fracture is described by arrays of box elements such that the regional change of fracture opening widths can be preserved. Compared with other fracture models (e.g. discrete fracture network), FBNM can simulate complicated multiphysical gas transport more efficiently, but also be able to simulate corresponding coal matrix deformation. By comparing permeability results between direct simulation method with FBNM, it is found that FBNM can effectively estimate the permeability of original fracture networks, but requiring significantly less computational cost. To study the implications of gas types, effective stress, gas adsorption, and thermal expansion on coal permeability, gas injection pressures, gas types, coal seam temperatures are varied and investigated in the simulations. In addition to the advantage of computational efficiency, FBNM is more preferable for complicated flow transport simulations where direct simulation methods are still challenging. This work provides a promising framework which could be further developed for multiphase and multicomponent flow simulations for CO2 geo-sequestration projects.

Estimation of the representative elementary volume of three-dimensional fracture networks based on permeability and trace map analysis: A case study

A three-dimensional (3D) discrete fracture network (DFN) was generated to evaluate the representative elementary volume (REV) of granitic rock masses based on the statistical geometry parameters mapped from outcrop surveys at the Xinchang site, China. Then, extensive numerical simulations were performed to investigate the effect of fracture density on the side length of models of the REV size (LREV). The relationship between LREV of 3D models and the geometric parameters of two-dimensional (2D) cutting planes parallel and perpendicular to the direction of hydraulic gradient variation were analyzed. This relationship was determined by calculating fluid flow through 90 original 3D models, 810 3D submodels, and 270 2D cutting models. Finally, two multivariable regression equations were proposed for predicting the LREV of the 3D fracture network and equivalent permeability of the REV size. The results show that the clustering results obtained from the 3D DFN model are similar to those obtained from field measurements. The values of LREV of the 3D DFN model based on statistical geometry parameters mapped from outcrops are 18.89 m, 19.56 m, and 24.86 m in three flow directions, respectively, which clearly highlights the anisotropic characteristics of fractured rock masses. The LREV decreases with increasing fracture density following an exponential relationship. The multivariable regression function estimates the evolution of the LREV of 3D DFN models with a wide range of fracture densities from 0.53 to 1.33 m/m2. The predicted results are more accurate than those predicted by the fitting function between the fracture density of 2D cutting planes perpendicular to the z-axis and LREV. The proposed model provides a method to approximate the LREV of 3D DFN models and equivalent permeability of the REV size (KREV) using geometric parameters of the 2D cutting planes obtained from trace map analysis of fractured rock masses.

Improving heat extraction performance of enhanced geothermal systems: Insights from critical fracture network parameter and multi-objective optimization method

• An integrated workflow is proposed for improving thermal recovery of hot dry rocks. • Network connectivity is a key fracture parameter in dominating thermal efficiency. • Network connectivity governs thermo-hydro-mechanical processes of fractured rocks. • Fractures with connectivity around 15–35 are better for production optimization. The generation of a highly permeable fracture network in Enhanced Geothermal Systems (EGSs) is a prerequisite to develop such geothermal reservoirs efficiently. However, it lacks a quantitative geometrical metric to evaluate what kind of fracture network is preferable for geothermal production. To address this problem, we use our previously developed high-fidelity Thermo-Hydro-Mechanical (THM) coupling model to investigate the joint influence of fracture geometry and thermal stress on the THM behaviors of EGSs. Results show that the geometrical connectivity of fracture networks plays a dominant role in determining the THM processes and the thermal performance of EGSs, in which the network connectivity integrates multiple properties of fracture networks including the fracture length, intensity, location and orientation. Satisfactory thermal performance tends to be achieved when the connectivity of fracture systems ranges from 15 to 35. We focus on such fracture networks and design an appropriate production scenario for optimizing multiple objectives (i.e. maximum EGS service life, heat extraction rate, and global thermal power). The overall heat extraction performance of EGSs under the optimum scenario gets improved by 77.7% compared with the base case. This research provides an effective workflow and feasible methods for evaluating and optimizing energy exploitation efficiency of EGSs.

Impacts of fracture properties on the formation and development of stimulated reservoir volume: A global sensitivity analysis

Stimulated reservoir volume (SRV), the highly permeable fracture network created by hydraulic fracturing, is essential for fluid production from low-permeable reservoirs. However, the configuration of SRV and its impacting factors are largely unknown. In this work, we adopt the stochastic discrete fracture network method to mimic natural fractures in subsurface formations and conduct a global sensitivity analysis with the Sobol method. The sensitivity of different fracture properties, including geometrical properties (fracture lengths, orientations, and center positions), mechanical properties (fracture roughness and fracture strength), fracture sealing properties (probabilities of open fractures and segment lengths), and the fracture intensity, are investigated in two and three-dimensional fracture networks. JRC-JCS model is adopted to identify critically stressed fractures. We find that critically stressed fractures compose the backbone of SRV, while partially open fractures can significantly enlarge the size of SRV by connecting more critically orientated fractures. The fracture roughness is the most influential factor for the total length (area) of critically stressed fractures. For the relative increase of SRV (RI) in 2D/3D fracture networks, the probability of open fractures is the most significant factor. The fracture lengths and center positions are essential factors for RI in 2D fracture networks but insignificant in 3D fracture networks. This work provides a realistic scenario of the subsurface structure and systematically investigates the influential factors of SRV, which is useful for estimating the size of SRV and predicting shale gas reservoirs’ production in an accurate and physically meaningful way.

Geological activity shapes the microbiome in deep-subsurface aquifers by advection

Subsurface environments host diverse microorganisms in fluid-filled fractures; however, little is known about how geological and hydrological processes shape the subterranean biosphere. Here, we sampled three flowing boreholes weekly for 10 mo in a 1478-m-deep fractured rock aquifer to study the role of fracture activity (defined as seismically or aseismically induced fracture aperture change) and advection on fluid-associated microbial community composition. We found that despite a largely stable deep-subsurface fluid microbiome, drastic community-level shifts occurred after events signifying physical changes in the permeable fracture network. The community-level shifts include the emergence of microbial families from undetected to over 50% relative abundance, as well as the replacement of the community in one borehole by the earlier community from a different borehole. Null-model analysis indicates that the observed spatial and temporal community turnover was primarily driven by stochastic processes (as opposed to deterministic processes). We, therefore, conclude that the observed community-level shifts resulted from the physical transport of distinct microbial communities from other fracture(s) that outpaced environmental selection. Given that geological activity is a major cause of fracture activity and that geological activity is ubiquitous across space and time on Earth, our findings suggest that advection induced by geological activity is a general mechanism shaping the microbial biogeography and diversity in deep-subsurface habitats across the globe.