Fracture Network Geometry 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.

Model Shows Computational Gains, Preserves Accuracy in Tight Rock EOR

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3834855, “Advanced Dual-Porosity and Dual-Permeability Model for Tight Rock Integrated Primary Depletion and Enhanced Oil Recovery Simulation,” by Daegil Yang, SPE, Tyler Do, and Changdong Yang, SPE, Chevron, et al. The paper has not been peer reviewed. _ Discrete fracture or dual-porosity modeling has been widely adopted for tight rock simulation. To represent the complex fracture heterogeneity and simplify its characterization, the authors present in the complete paper a new simulation model to holistically optimize the tight rock reservoir completion, primary depletion, and enhanced oil recovery modeling and retain the injection mechanism and simplify the complex fracture characterization to enhance computational efficiency. The model enables users to characterize different properties in multiple regions. This tool will have broad applications in supporting asset-development decisions. Introduction Traditional dual-porosity, dual-permeability (DPDK) simulation incorporates microscale fracture characterization through the shape factor (matrix/fracture coupling), which offers a significant contact area for the gas/oil mixture to represent the field response reliably. However, its homogeneous fracture network cannot be used to optimize the completion design. The authors have developed what they refer to as the advanced DPDK (A-DPDK) simulation work flow to maintain heterogeneous fracture characterization and to simplify microfracture characterization. The work flow contains the following features: - A newly derived shape-factor algorithm that can represent the scale and heterogeneity of the fracture network - Local grid refinement (LGR) that accelerates the speed of computation (five-times-faster acceleration) and improves accuracy - A fracture-characterization feature that serves as a helpful diagnostic tool to assign a flexible cutoff value for both propped fractures (PF) and unpropped fractures to enhance simulation speed and robustness - A connected PF feature that can label the effective fracture region to simplify completion design work flow and prioritize reservoir simulation The authors validated the new features implemented in the work flow systematically and demonstrated the benefits of the proposed work flow. The authors also applied the work flow in one gas-injection pilot and successfully history-matched the primary depletion and the gas-injection response. Modeling Approach The A-DPDK model design is aimed at modeling a complex fracture network using a structured grid system while maintaining the background natural fracture. In the modeling process, the main fracture network is screened and identified and its transmissibility calculated. Then, the microfracture is calculated to matrix mass transfer. This can be numerically modeled using a DPDK framework. The geometry of the hydraulic fracture network is preserved explicitly as grid cells in the fracture domain. Also, in the matrix domain, the enhanced permeability region (EPR), which represents the microfracture, is included. The mass transfer between matrix cells and the EPR is modeled as a grid-cell connection (transmissibility), and the mass transfer between the hydraulic fracture cells and the microfractures is modeled as a grid-cell connection as well. A new way of calculating the coupling term that models the mass transfer between the hydraulic fracture and the EPR and the matrix is introduced.

Bedrock Fractures Control Groundwater‐Driven Mountain Slope Deformations

AbstractSeasonal deformation of mountain rock slopes can be driven by groundwater infiltration and depletion. Such processes could explain our field observation in the Aletsch Valley, Switzerland, where GNSS‐derived 3D annual displacement amplitudes reach 3.4 cm. However, the physical mechanisms behind such groundwater‐driven surface displacements are not well understood. Here, we develop a fully coupled hydromechanical model to simulate the relevant processes in a valley slope embedded with numerous fractures of variable sizes. The magnitude and orientation of transient annual slope surface displacement obtained from our model are in overall agreement with the field observations. The key geological factors controlling the type and magnitude of reversible mountain slope deformations are fracture network geometry, fracture aperture, and regional stress field. We show that the heterogeneity and anisotropy of bedrock hydromechanical responses, originating from depth‐dependent variations of fracture properties, play a critical role in groundwater recharge and valley slope deformation. During recharge events, pore pressure perturbations migrate downward from the groundwater table and toward the receiving stream and the deep subsurface. This process driven by pressure diffusion and poroelastic stressing develops in the subsurface with a great reach of up to a few kilometers, called critical hydromechanical response zone, and controls surface deformation patterns. During groundwater recession, this hydromechanical response zone expands downward and ground surface displacement vectors rotate upwards. Our results suggest that slope surface deformation can inform about subsurface permeability structures and pore pressure fluctuations, which have important implications for understanding groundwater flow in fractured bedrock slopes.

Permeability model of fracture network based on branch length distribution and topological connectivity

Fracture networks are of significance in the production of coalbed methane from unconventional reservoirs. However, the complex distribution and geometry of fracture networks make effective predictions of their permeability difficult. This study obtains the shape of a natural fracture network in coal based on a stereomicroscopy experiment and analyzes the structural characteristics of the fracture network using graph theory. The fractal scaling law for the branch length distribution of the fractures and the relationships among the fractal dimensions of the branch length distribution, fracture area, porosity, connectivity, and ratio of maximum to minimum branch length are established. A new permeability model for a complex fracture network is developed based on fractal theory, and two important fracture characteristics, namely, tortuosity and connectivity, are considered. The model is verified using the results of previous studies and seepage tests, and the influence of the fracture network characteristic parameters on the permeability is analyzed. The results show that the permeability increases with increasing porosity, fractal dimension, proportionality coefficient, maximum fracture branch length, and connectivity and decreases with increasing tortuosity fractal dimension and dip angle.

Efficient fracture network characterization in enhanced geothermal reservoirs by the integration of microseismic and borehole logs data

Characterization of 3D fracture networks induced by hydraulic fracturing in enhanced geothermal reservoirs is crucial for safe and effective energy recovery from deep geothermal reservoirs. Microseismic monitoring is one of the most promising ways to infer the geometry of fracture network. However, the identification of fracture network from microseismic events is still a challenging task, attributed to high noises in microseismicity interpretation and fuzzy relationships between microseismic event locations and fracture planes. This study proposed a novel methodology to identify fracture network from the spatial distribution of microseismic events. The method was composed by (1) density-based spatial clustering algorithm for microseismic data denoising, (2) Monte Carlo optimization algorithm for fractures localization by minimizing the total distance between denoised microseismic events and fracture planes, and (3) Elbow method to decide the most likely number of fractures. Moreover, the method employed the prior knowledge of geo-stresses and initial fracture patterns inferred from borehole logs to constrain the geometry of fracture network. Following verifications with synthetic fractures and microseismic events, the method was implemented in a realistic enhanced geothermal system, which reliably identified the geometry of 3D fracture network induced by hydraulic fracturing.

A New Method to Three-dimensional Dual Medium Geometry Model Construction

Dual medium geometric model is widely used in soil and rock mass environment, which can only reflect the material exchange between cracks and matrix. The dual medium geometric model ignores the hydraulic relationship between the pores and cracks. The paper develops a new method to construct the three-dimensional dual medium geometry model. This method is completely written by Matlab scripting language, can describe the real spatial distribution state of fracture in bedrock. In the method, three-dimensional random fracture network geometric models with different parameters and three-dimensional porous media geometric models with Berlin Noise characteristics are constructed respectively, and then use the three-dimensional direct superposition method to construct the dual medium geometric model. The paper introduces the construction of three-dimensional random fracture network geometry model, three-dimensional porous media geometric model and the dual medium geometric model by direct superposition method. This research is of great significance to the construction of dual medium model and numerical simulation in related fields.

Autonomous fracture flow tunning to enhance efficiency of fractured geothermal systems

To avoid any shortcuts that may “short-circuit” the fluid flow between the injection and production wells in an enhanced geothermal system (EGS), we explore the idea of autonomous in-situ tunning of fracture hydraulic conductivity (FCTT) and its potential benefits. The new technique is expected to provide variable fracture hydraulic conductivity depending on the surrounding temperature. Through FCTT, we can effectively manage the fluid flow in the reservoir and promote a uniform thermal gradient along the flow paths. A numerical finite element model is established to assess the impact of tunning magnitude and fracture network geometries on the production efficiency of EGSs. Results show that utilizing this technique could prevent an early appearance of fluid flow shortcut between injector and producer in an EGS. After 50 years of production, the output thermal power with the technique could be increased by 67.51%. Furthermore, we found that fracture density and fracture network connectivity in the reservoir could affect performance improvement reached by FCTT in production. We also present a field case with a realistic fracture network. After 50 years of production, applying this technique increases heat extraction by 101.78% in fracture networks that are expected in EGS. Since other flow-control systems in geothermal production are mainly focused on the wellbore and near-wellbore areas, this technique can provide a more effective enhancement in heat extraction by controlling flow deep inside the reservoir.

Production performance simulation of a horizontal well in a shale gas reservoir considering the propagation of hydraulic fractures

In recent years, shale gas has become an important energy source due to its abundant reserves. Due to their extremely tight initial properties, shale gas reservoirs require the use of the multi-stage fractured horizontal well (MFHW) technique to break the shale rock, activate closed natural fractures, and form a complex fracture network. In this study, to solve the issue of how to describe the fracture network's geometry and to predict the production performance accurately, a model that couples the fracture propagation with the fracturing fluid and proppant flow in a horizontal wellbore and hydraulic fractures is established. The displacement discontinuity method (DDM) and finite volume method are used to iteratively obtain numerical simulations of the fracture propagation. The accuracy of the fracture propagation model is verified through comparison with analytical and numerical models. Then, the coupled continuous media and discrete fracture network model considering multiscale flow mechanisms in shale is developed, which is solved numerically using the control volume finite element method (CVFEM) and unstructured tri-prism grids. Finally, the numerical simulation models are successfully applied to synthetic and field cases, sensitivity analysis is conducted to evaluate the influences of the proppant injection, stress anisotropy and distribution of the natural fractures on the fracture propagation and production performance of the MFHW in a shale gas reservoir.

3D natural fracture model of shale reservoir based on petrophysical characterization

The existence and distribution of natural fractures in shale reservoirs is of great significance to shale gas exploitation. A 3D fracture spatial distribution model with varying reservoir burial depth and regional tectonicsin southeastern Chongqing is constructed based on an enhanced DFN modeling method. Fracture volume density (P32) is calculated by petrophysical test and verified from test wells. The geometric parameters of fractures (length, occurrence, opening) are clustered by regional tectonics. Uncertainties are considered by a stochastic description of the fracture network geometry, utilizing Monte Carlo simulation techniques. The application of the model in seven wells and the quantitative analysis of the relationship between fracture density and burial depth allow the modeling to be extended to deep and ultra-deep reservoirs. Fracture models with reservoirs buried depth over 3000 m are predicted and analyzed. For the various input parameters, the influence of model size and fracture shape on model reliability is analyzed. The establishment of fracture model can effectively quantitatively characterize the reservoir fracture distribution at different burial depths, and its efficient implementation in finite element software can provide support for shale gas mining engineering.

Factors Controlling the Flow and Connectivity in Fracture Networks in Naturally Fractured Geothermal Formations

Summary The productivity and injectivity of hydraulically fractured geothermal wells in naturally fractured formations depend on the connectivity of fracture networks created by the interaction of hydraulic fractures with natural fractures. The primary objectives of this paper are (a) to define quantitatively the connectivity of the created fracture network, (b) to determine the factors that control the connectivity of fracture networks bounded by wells, and (c) to propose ways in which the flow capacity and fracture connectivity can be improved by changes to the hydraulic fracture design. A fully 3D hydraulic fracturing simulator has been developed that considers the interaction of hydraulic fractures with natural fractures by solving for the stresses, fluid flow, heat transfer, fracture growth, and intersection. These propagated fractures, which include hydraulic fractures and reactivated natural fractures, are divided into backbone, dead-end, and isolated fractures. Different well patterns that aim to optimize the connectivity of the injector to the producer (optimize the area of the backbone fractures) are simulated. A sensitivity analysis is conducted to investigate the effect of various parameters on the connectivity of wells through fractures. An optimal well pattern is needed to maximize the connected fracture area that provides a conductive path for heat extraction from naturally fractured geothermal reservoirs. Our results show that the connectivity of fracture networks is dramatically impacted by the degree of deflection, crossing, and merging of hydraulic fractures with natural fractures. An example is used to investigate the effect of backbone and dead-end fractures on heat extraction from an enhanced geothermal system (EGS). The detailed parametric study helps us better understand the factors that influence the geometry and connectivity of fracture networks and guide us in hydraulic fracture design and well spacing optimization in naturally fractured geothermal reservoirs.

Long‐Wavelength Propagation in Fractured Rock Masses (3D Stress Field)

AbstractFractured rocks affect a wide range of natural processes and engineering systems. In most cases, the seismic characterization of fractured rock masses in the field involves wavelengths much longer than the fracture spacing; reproducing this condition in the laboratory is experimentally challenging. This experimental investigation explores the effect of fracture rock fabric and the 3D stress field on P wave propagation in the long‐wavelength regime using a large‐scale true triaxial device. P wave velocities increase with stress in the propagation direction and follow a power law of the form Vp = α(σ’/kPa)β; analyses and experimental results show that stress‐sensitive fracture stiffness and fracture density define the α‐factor and β‐exponent; conversely, long‐wavelength velocity versus stress data can be analyzed to identify the stress‐dependent fracture stiffness. P wave velocities exhibit hysteretic behavior caused by inelastic fracture deformation and fabric changes. During deviatoric loading, the P wave velocity decreases in the two constant‐stress directions due to the development of internal force chains and the ensuing three‐dimensional deformation. Following a load increment, time‐dependent contact deformations result in P wave velocity changes during the first several hours for the tested carbonate rocks; the asymptotic change in velocity is more pronounced for higher stress changes and stress levels. The fracture network geometry that defines the rock fabric acts as a low‐pass filter to wave propagation, so that wavelengths must be longer than two times the fracture spacing to propagate (Brillouin dispersion); the long‐wavelength velocity and the fracture spacing determine the cutoff frequency. Fabric anisotropy contributes to anisotropic low‐pass filtering effects in the rock mass.

The role of fracture branching in the evolution of fracture networks: An outcrop study of the Jurassic Navajo Sandstone, southern Utah

Fractures strongly influence the permeability of geologic formations, and because most fractures in the subsurface are below the resolution of geophysical methods, predicting the spatial evolution of fracture networks is important for groundwater resources, oil and gas production, and geothermal energy. Previous researchers have established that variations in lithologic mechanical properties influence the propagation of joints and fractures in layered rocks under stable stress conditions, but few studies have addressed how instabilities in local stress fields, in conjunction with variations in rock mechanical properties, lead to fracture branching.We investigate NE-striking fractures in the footwall of the west-dipping Sevier fault in Utah, USA, where canyons expose the sub-horizontal Jurassic Navajo Sandstone. We analyzed field data, petrographic data, and unmanned-aerial-vehicle (UAV) imagery to document the fracture network. We also used structure-from-motion (SfM) software to build a 3D virtual outcrop model, measuring 100 m high and 260 m wide, to aid our analysis of fracture network geometry, intensity, and spacing variations.Data reveal an up-section increase in fracture intensity and decrease in spacing regularity partly accommodated by upward fracture branching. We suggest that branching was initiated by a combination of changes in mechanical behavior within cross-bed sets and twist hackle propagation associated with mixed mode fracture systems. These tree-like fracture geometries may be associated with high-velocity, earthquake-related fracture propagation events. Fracture branching strongly influences permeability and should be considered by researchers investigating fracture development in subsurface systems.

The impact of changes in natural fracture fluid pressure on the creation of fracture networks

Complex fracture networks have been observed in mine-back experiments, core samples, and other fracture diagnostic measurements. The interaction between hydraulic and natural fractures plays a key role in the formation of this complexity in naturally fractured formations. In past studies, changes in fluid pressure in natural fractures induced by interaction with other fractures are neglected when interactions between natural and hydraulic fractures are considered. In this paper, a DDM-based hydraulic fracturing simulator is developed to investigate the effect of changes in fluid pressure in natural fractures on fracture behavior and the resulting geometry of complex fracture networks. A fully implicit method is used to solve for width and pressure simultaneously. The proposed model is validated against an analytical solution for such variations in the vicinity of a penny-shaped fracture. Two kinds of interactions between hydraulic and natural fractures are defined to clearly investigate the mechanism of the far-field failure of natural fractures. Comparisons with and without considering changes in fluid pressure in natural fractures are conducted to show how the geometry of hydraulic fractures changes when changes in fluid pressure in fractures are included. Key parameters such as in-situ stress, natural fracture orientation, and friction coefficient are varied to develop new failure and crossing criteria under different conditions.Simulation results show that (1) changes in fluid pressure in fractures can initiate isolated fractures to create a stimulated rock volume. In some instances this will result in a more branched and complex fracture network; (2) deflection of hydraulic fractures along natural fractures is promoted when the effect of changes in fluid pressure in natural fractures is taken into account; (3) hydraulic fractures tend to deflect along pre-existing natural fractures with no far-field failure when the stress contrast is low; (4) in formations with high in-situ stress contrast, far-field failure of natural fractures occurs more readily and is impacted by the orientation and frictional coefficient of the natural fractures; (5) as expected, well cemented (highly mineralized) fractures with larger frictional coefficients hinder the slip of natural fractures and result in more planar less branched fractures. The results for failure and crossing criteria we developed can improve the understanding of the formation of complex fracture networks in naturally fractured rocks.

Combinatorial topology and geometry of fracture networks.

A map is proposed from the space of planar surface fracture networks to a four-parameter mathematical space, summarizing the average topological connectivity and geometrical properties of a network idealized as a convex polygonal mesh. The four parameters are identified as the average number of nodes and edges, the angular defect with respect to regular polygons, and the isoperimetric ratio. The map serves as a low-dimensional signature of the fracture network and is visually presented as a pair of three-dimensional graphs. A systematic study is made of a wide collection of real crack networks for various materials, collected from different sources. To identify the characteristics of the real materials, several well-known mathematical models of convex polygonal networks are presented and worked out. These geometric models may correspond to different physical fracturing processes. The proposed map is shown to be discriminative, and the points corresponding to materials of similar properties are found to form closely spaced groups in the parameter space. Results for the real and simulated systems are compared in an attempt to identify crack networks of unknown materials.

Discrete fracture network (DFN) modelling of a high-level radioactive waste repository host rock and the effects on its hydrogeological behaviour

Fracture network modelling and a hydrological evaluation were performed in a well more than 900 m deep that penetrated the Boda Claystone Formation, a potential host rock for high-level nuclear waste disposal facilities in Hungary. The fracture network geometry was generated with a discrete fracture network algorithm, in which the permeability and porosity of the system can be calculated if the aperture of the fractures is known. The hydrological aperture of the fractures was estimated via an aperture calibration based on a comparison of the measured and modelled permeability values. Flow zone indices were calculated for numerous sections along the well, designating hydraulic units, in which the fluid flow-controlling properties are internally even.Based on the fracture network geometry and the hydraulic flow units, most parts of the well behave uniformly, while three narrow zones differ significantly. The first zone is located in the upper 100 m of the well probably formed due to weathering. The second zone is located at approximately 400 m, where a large-scale structural boundary is presumed. In the third zone at 700 m, a lithological change greatly affects the hydrological properties, but the influence of tectonic processes cannot be ruled out.

A New Projection-Based Integrally Embedded Discrete Fracture Model and Its Application in Coupled Flow and Geomechanical Simulation for Fractured Reservoirs

The embedded discrete fracture model (EDFM) has been popular for the modeling of fractured reservoirs due to its flexibility and efficiency while maintaining the complex geometry of fracture networks. Though the EDFM has been validated for single-phase flow simulations, some recent cases show that the EDFM might result in apparent errors in multiphase flow situations. The projection-based embedded discrete fracture model (pEDFM) and the integrally embedded discrete fracture model (IEDFM) are two recently developed methods, which intend to improve the accuracy of the EDFM. In this study, a projection-based integrally embedded discrete fracture model (pIEDFM) is proposed, which combines the advantages of the pEDFM and the IEDFM. Similar to the pEDFM, the pIEDFM uses a kind of additional connections between fracture and nonneighboring matrix cells to obtain more physically authentic velocity fields. As a significant improvement, a semi-analytical cone-shaped pressure distribution that follows the IEDFM is adopted in the pIEDFM to capture the sharp pressure change near the fracture surfaces. Comparisons with benchmark results and explicit-fracture fine grid simulation results show that the pIEDFM provides accurate solutions using a moderate amount of grids. The proposed pIEDFM is also applied to coupled flow and geomechanical simulation for fractured reservoirs. Comparison of our coupled simulation results with that of the EDFM shows that the pIEDFM is applicable for the coupled simulation, and the different methods for matrix-fracture transmissibility between the pIEDFM and the EDFM may lead to deviations in stress fields predicted by geomechanical modeling, which eventually affects the oil production, water cut, and oil saturation profiles.

A proxy model to predict reservoir dynamic pressure profile of fracture network based on deep convolutional generative adversarial networks (DCGAN)

Tight oil and gas reservoirs with huge development potential are widely distributed all over the world and horizontal well technique is a popular development technology for such kinds of reservoirs. However, the efficiency of conventional horizontal well technology is usually unsatisfying due to the unfavorable flow conditions caused by the nature of tight reservoirs, such as low matrix permeability and narrow pore throat. Multi-stage fractured horizontal well technology is an emerging attractive technology that can greatly improve oil production by generating highly conductive fracture networks in tight reservoirs. and numerical simulation method is generally used to predict the production dynamics of the multi-stage fractured horizontal wells. Nevertheless, the complex geological conditions of reservoirs would greatly increase the difficulties and time required to implement a complete simulation (including model building and calculation). Therefore, in this paper, deep convolution generative adversarial networks (DCGAN) based on U-Net framework was applied to establish the dynamic mapping relationship between fracture pattern and reservoir pressure during the production process, that is, the dynamic reservoir pressure distribution can be obtained by image mapping the fracture distribution details. The results showed that the efficiency of U-Net framework based deep convolution in extracting, dividing and splicing the geometric features of fracture network is significant, and the generative adversarial networks model can effectively predict the reservoir pressure distribution according to the fracture network geometry after being trained with 6000 sets of data. Herein, the training accuracy of the proxy model towards sample data was compared, and the confrontation between the generator and the discriminator in the iterative training process was clarified according to the error function. Furthermore, the prediction accuracy towards pressure distribution at different fracture network geometry scales by the proxy model was compared. Results indicated that the pressure diffusion range predicted by the proxy model is basically consistent with the range obtained from the numerical simulation, with a mean square error (MSE) generally smaller than 0.2. In addition, the relationship between the prediction accuracy of the proxy model and the number of sample data and iterative training times was also studied, which showed that the mean square error of the proxy model kept decreasing with the increasing iteration cycles and sample size, which met the basic law of statistical learning. Moreover, it is worth mentioning that the proposed method may also shed light on the applications of DCGAN in other reservoir-related problems.

A workflow of fracture geometry diagnostics of unconventional wells with complex fracture networks coupling fracture mapping and well testing

Although many attempts have been made for fracture diagnostics, the complex fracture-network geometries are still ineffectively identified. To improve this situation, this study develops a new workflow to determine the geometries of complex fracture networks of unconventional wells. The theoretical basis of this workflow is containing fracture mapping based on Hough transform and well testing based on semi-analytical model. The flexibility and reliability on identifications of complex-fracture geometries are demonstrated through the case studies. Subsequently, the proposed workflow is applied to perform field application with microseismic data and identify the most likely fracture geometry. Results show that different geometries of fracture networks have different features of flow regimes, which are totally distinct from those of traditional bi-wing fractures. A special “hump” occurs if the fracture geometry is dendritic, and a feature of “fluid feed” from fracture branches to wellbore-connected fracture may occur, and the “pseudo boundary dominated flow” appears for an orthogonal fracture networks. The “fluid feed”, “fracture interferences”, and “pseudo boundary-dominated flow” are respectively demonstrated by a dual-porosity feature, namely “V-shape”, a “hump”, and a unit-slope line, which are good tools for fracture-geometry diagnostics. By performing a field application, the estimated fracture-network geometry of well QW1 from the Ordos Basin is obtained using the proposed workflow. The results demonstrate that mutually orthogonal fracture networks may not be generated. This study demonstrates a new way for fracture geometry diagnostics of unconventional wells with complex fracture networks.

Formation mechanisms of hydraulic fracture network based on fracture interaction

The interaction between hydraulic fractures and natural fractures have significant influence on the geometry of hydraulic fracture network in fractured reservoirs. In previous mathematical model, the interaction relationship of non-intersecting fractures in propagation process were often been ignored, which resulted the inaccuracy of simulation results. Based on boundary element method and rock failure criterion, we established mathematical model to study the fracture interaction mechanisms and fracture network morphology under induced stress. Simulation results show that hydraulic fracture with incipient propagation superiority are more likely to have a rapid propagation and inhibit the continuous initiation of surrounding micro fractures. Under proper conditions, single natural fracture can deflect the propagation direction of hydraulic fracture by at least 22°. Firstly proposed that shielding and transmission efforts of induced stress by natural fracture are the fundamental reason that affect the complexity of fracture network, which can reduce the normal stress around natural fracture by 50% in this paper. When the inclination Angle of natural fractures is between 45 and 70°, it is more favorable to form complex fracture network. This study is of great significance for the control of fracture network morphology and the further improvement of fracturing effect.

Modelling discontinuity control on the development of Hell\u2019s Mouth landslide

This paper focuses on numerical modelling and back analysis of the Hell’s Mouth landslide to provide improved understanding of the evolution of a section of the north coast of Cornwall, UK. Discontinuity control is highlighted through the formation of a ‘zawn’ or inlet, the occurrence of two successive landslides and evidence of ongoing instability through opening of tension cracks behind the cliff top. Several integrated remote sensing (RS) techniques have been utilised for data acquisition to characterise the slope geometry, landslide features and tension crack extent and development. In view of the structural control on the rock slope failures, a 3D distinct element method (DEM) code incorporating a discrete fracture network and rigid blocks has been adopted for the stability analysis. The onset and opening of tension cracks behind the modelled slope failure zones has also been studied by analysing the displacements of two adjoining landslide blocks, between which, a joint-related tension crack developed. In addition, a sensitivity analysis has been undertaken to provide further insight into the influence of key discontinuity parameters (i.e. dip, dip direction, persistence and friction angle) on the stability of this section of the coastline. Numerical modelling and field observations indicate that block removal and preferential erosion along a fault resulted in the formation of the inlet. The development of the inlet provides daylighting conditions for discontinuities exposed on the inlet slope wall, triggering the initial landslide which occurred on 23rd September 2011. Numerical modelling, and evidence from a video of the initial landslide, suggests that the cliff instability is characterised by a combination of planar sliding, wedge sliding and toppling modes of failure controlled by the discrete fracture network geometry.